<?xml version="1.0" encoding="UTF-8"?>
<FEDREG xmlns:xsi="http://www.w3.org/2001/XMLSchema-instance" xsi:noNamespaceSchemaLocation="FRMergedXML.xsd">
    <VOL>89</VOL>
    <NO>94</NO>
    <DATE>Tuesday, May 14, 2024</DATE>
    <UNITNAME>Contents</UNITNAME>
    <CNTNTS>
        <AGCY>
            <EAR>
                Agriculture
                <PRTPAGE P="iii"/>
            </EAR>
            <HD>Agriculture Department</HD>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>Rural Housing Service</P>
            </SEE>
            <CAT>
                <HD>NOTICES</HD>
                <DOCENT>
                    <DOC>Agency Information Collection Activities; Proposals, Submissions, and Approvals, </DOC>
                    <PGS>41925-41928</PGS>
                    <FRDOCBP>2024-10536</FRDOCBP>
                      
                    <FRDOCBP>2024-10542</FRDOCBP>
                </DOCENT>
                <SJ>Agency Information Collection Activities; Proposals, Submissions, and Approvals:</SJ>
                <SJDENT>
                    <SJDOC>Digitized Advisory Committee and Research and Promotion Background Information Revised Supplemental Lists and including Marketing Collection, </SJDOC>
                    <PGS>41926-41927</PGS>
                    <FRDOCBP>2024-10484</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Centers Medicare</EAR>
            <HD>Centers for Medicare &amp; Medicaid Services</HD>
            <CAT>
                <HD>NOTICES</HD>
                <DOCENT>
                    <DOC>Agency Information Collection Activities; Proposals, Submissions, and Approvals, </DOC>
                    <PGS>41967-41968</PGS>
                    <FRDOCBP>2024-10541</FRDOCBP>
                      
                    <FRDOCBP>2024-10545</FRDOCBP>
                </DOCENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Coast Guard</EAR>
            <HD>Coast Guard</HD>
            <CAT>
                <HD>RULES</HD>
                <SJ>Safety Zone:</SJ>
                <SJDENT>
                    <SJDOC>Vineyard Wind 1 Wind Farm Project Area, Outer Continental Shelf, Lease OCS-A 0501, Offshore Massachusetts, Atlantic Ocean, </SJDOC>
                    <PGS>41895</PGS>
                    <FRDOCBP>2024-10481</FRDOCBP>
                </SJDENT>
            </CAT>
            <CAT>
                <HD>PROPOSED RULES</HD>
                <SJ>Special Local Regulation:</SJ>
                <SJDENT>
                    <SJDOC>Clear Lake, Clear Creek, TX, </SJDOC>
                    <PGS>41914-41916</PGS>
                    <FRDOCBP>2024-10216</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Commerce</EAR>
            <HD>Commerce Department</HD>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>Industry and Security Bureau</P>
            </SEE>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>International Trade Administration</P>
            </SEE>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>National Oceanic and Atmospheric Administration</P>
            </SEE>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>Patent and Trademark Office</P>
            </SEE>
        </AGCY>
        <AGCY>
            <EAR>Defense Department</EAR>
            <HD>Defense Department</HD>
            <CAT>
                <HD>RULES</HD>
                <SJ>Acquisition Regulation:</SJ>
                <SJDENT>
                    <SJDOC>Technical Amendments; Correction, </SJDOC>
                    <PGS>41895-41896</PGS>
                    <FRDOCBP>2024-10499</FRDOCBP>
                </SJDENT>
            </CAT>
            <CAT>
                <HD>NOTICES</HD>
                <DOCENT>
                    <DOC>Arms Sales, </DOC>
                    <PGS>41950-41963</PGS>
                    <FRDOCBP>2024-10470</FRDOCBP>
                      
                    <FRDOCBP>2024-10471</FRDOCBP>
                      
                    <FRDOCBP>2024-10472</FRDOCBP>
                      
                    <FRDOCBP>2024-10473</FRDOCBP>
                      
                    <FRDOCBP>2024-10469</FRDOCBP>
                </DOCENT>
                <SJ>Charter Amendments, Establishments, Renewals and Terminations:</SJ>
                <SJDENT>
                    <SJDOC>Board on Coastal Engineering Research, </SJDOC>
                    <PGS>41963-41964</PGS>
                    <FRDOCBP>2024-10478</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Education Department</EAR>
            <HD>Education Department</HD>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>National Assessment Governing Board</P>
            </SEE>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Agency Information Collection Activities; Proposals, Submissions, and Approvals:</SJ>
                <SJDENT>
                    <SJDOC>Campus Safety and Security Survey, </SJDOC>
                    <PGS>41964-41965</PGS>
                    <FRDOCBP>2024-10488</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Energy Department</EAR>
            <HD>Energy Department</HD>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>Federal Energy Regulatory Commission</P>
            </SEE>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Hearings, Meetings, Proceedings, etc.:</SJ>
                <SJDENT>
                    <SJDOC>Environmental Management Site-Specific Advisory Board, Portsmouth, </SJDOC>
                    <PGS>41965</PGS>
                    <FRDOCBP>2024-10489</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Environmental Protection</EAR>
            <HD>Environmental Protection Agency</HD>
            <CAT>
                <HD>RULES</HD>
                <SJ>Greenhouse Gas Reporting Rule:</SJ>
                <SJDENT>
                    <SJDOC>Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems, </SJDOC>
                    <PGS>42062-42327</PGS>
                    <FRDOCBP>2024-08988</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Federal Aviation</EAR>
            <HD>Federal Aviation Administration</HD>
            <CAT>
                <HD>RULES</HD>
                <DOCENT>
                    <DOC>Standard Instrument Approach Procedures, and Takeoff Minimums and Obstacle Departure Procedures, </DOC>
                    <PGS>41883-41886</PGS>
                    <FRDOCBP>2024-10322</FRDOCBP>
                      
                    <FRDOCBP>2024-10323</FRDOCBP>
                </DOCENT>
            </CAT>
            <CAT>
                <HD>PROPOSED RULES</HD>
                <SJ>Airworthiness Directives:</SJ>
                <SJDENT>
                    <SJDOC>Bell Textron Canada Limited Helicopters, </SJDOC>
                    <PGS>41906-41908</PGS>
                    <FRDOCBP>2024-09544</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Saab AB, (Formerly Known as Saab AB, Support and Services) Airplanes, </SJDOC>
                    <PGS>41903-41906</PGS>
                    <FRDOCBP>2024-09513</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>The Boeing Company Airplanes, </SJDOC>
                    <PGS>41908-41912</PGS>
                    <FRDOCBP>2024-09545</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Federal Election</EAR>
            <HD>Federal Election Commission</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Filing Dates:</SJ>
                <SJDENT>
                    <SJDOC>New Jersey Special Election in the 10th Congressional District, </SJDOC>
                    <PGS>41966-41967</PGS>
                    <FRDOCBP>2024-10501</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Federal Emergency</EAR>
            <HD>Federal Emergency Management Agency</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Disaster or Emergency Declaration and Related Determination:</SJ>
                <SJDENT>
                    <SJDOC>Alaska, </SJDOC>
                    <PGS>41976</PGS>
                    <FRDOCBP>2024-10458</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>California, </SJDOC>
                    <PGS>41975-41976</PGS>
                    <FRDOCBP>2024-10460</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Florida; Amendment No. 1, </SJDOC>
                    <PGS>41974</PGS>
                    <FRDOCBP>2024-10443</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Florida; Amendment No. 16, </SJDOC>
                    <PGS>41977</PGS>
                    <FRDOCBP>2024-10439</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Florida; Amendment No. 3, </SJDOC>
                    <PGS>41974</PGS>
                    <FRDOCBP>2024-10440</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Florida; Amendment No. 8, </SJDOC>
                    <PGS>41979</PGS>
                    <FRDOCBP>2024-10446</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Louisiana; Amendment No. 3, </SJDOC>
                    <PGS>41980</PGS>
                    <FRDOCBP>2024-10438</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Maine, </SJDOC>
                    <PGS>41976-41977</PGS>
                    <FRDOCBP>2024-10455</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Maine; Amendment No. 1, </SJDOC>
                    <PGS>41973, 41977, 41979-41981</PGS>
                    <FRDOCBP>2024-10441</FRDOCBP>
                      
                    <FRDOCBP>2024-10444</FRDOCBP>
                      
                    <FRDOCBP>2024-10447</FRDOCBP>
                      
                    <FRDOCBP>2024-10448</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Maine; Amendment No. 2, </SJDOC>
                    <PGS>41982</PGS>
                    <FRDOCBP>2024-10450</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Mississippi; Amendment No. 3, </SJDOC>
                    <PGS>41978-41979</PGS>
                    <FRDOCBP>2024-10445</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Mississippi; Amendment No. 5, </SJDOC>
                    <PGS>41974</PGS>
                    <FRDOCBP>2024-10442</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>New Hampshire, </SJDOC>
                    <PGS>41981-41982</PGS>
                    <FRDOCBP>2024-10452</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Oregon, </SJDOC>
                    <PGS>41980</PGS>
                    <FRDOCBP>2024-10459</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Rhode Island, </SJDOC>
                    <PGS>41975, 41977-41978</PGS>
                    <FRDOCBP>2024-10456</FRDOCBP>
                      
                    <FRDOCBP>2024-10457</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Utah; Amendment No. 1, </SJDOC>
                    <PGS>41982</PGS>
                    <FRDOCBP>2024-10449</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Vermont, </SJDOC>
                    <PGS>41978</PGS>
                    <FRDOCBP>2024-10453</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Washington; Amendment No. 2, </SJDOC>
                    <PGS>41979</PGS>
                    <FRDOCBP>2024-10451</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Wrangell Cooperative Association, </SJDOC>
                    <PGS>41980-41981</PGS>
                    <FRDOCBP>2024-10454</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Federal Energy</EAR>
            <HD>Federal Energy Regulatory Commission</HD>
            <CAT>
                <HD>NOTICES</HD>
                <DOCENT>
                    <DOC>Combined Filings, </DOC>
                    <PGS>41965</PGS>
                    <FRDOCBP>2024-10549</FRDOCBP>
                </DOCENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Federal Maritime</EAR>
            <HD>Federal Maritime Commission</HD>
            <CAT>
                <HD>RULES</HD>
                <DOCENT>
                    <DOC>Demurrage and Detention Billing Requirements, </DOC>
                    <PGS>41895</PGS>
                    <FRDOCBP>2024-10515</FRDOCBP>
                </DOCENT>
            </CAT>
            <CAT>
                <HD>NOTICES</HD>
                <DOCENT>
                    <DOC>Complaint, </DOC>
                    <PGS>41967</PGS>
                    <FRDOCBP>2024-10433</FRDOCBP>
                </DOCENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Federal Motor</EAR>
            <HD>Federal Motor Carrier Safety Administration</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Exemption Application:</SJ>
                <SJDENT>
                    <SJDOC>Commercial Driver's License Standards: CRST the Transportation Solution (Formerly Known as CRST Expedited, Inc.), </SJDOC>
                    <PGS>42055-42056</PGS>
                    <FRDOCBP>2024-10540</FRDOCBP>
                </SJDENT>
                <SJ>Revision to Pilot Program Requirements:</SJ>
                <SJDENT>
                    <SJDOC>Safe Driver Apprenticeship Pilot Program to Allow Persons Ages 18, 19, and 20 to Operate Commercial Motor Vehicles in Interstate Commerce, </SJDOC>
                    <PGS>42054-42055</PGS>
                    <FRDOCBP>2024-10538</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>
                General Services
                <PRTPAGE P="iv"/>
            </EAR>
            <HD>General Services Administration</HD>
            <CAT>
                <HD>RULES</HD>
                <SJ>Acquisition Regulation:</SJ>
                <SJDENT>
                    <SJDOC>Technical Amendments; Correction, </SJDOC>
                    <PGS>41895-41896</PGS>
                    <FRDOCBP>2024-10499</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Geological</EAR>
            <HD>Geological Survey</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Agency Information Collection Activities; Proposals, Submissions, and Approvals:</SJ>
                <SJDENT>
                    <SJDOC>Did You Feel It Earthquake Questionnaire, </SJDOC>
                    <PGS>41982-41983</PGS>
                    <FRDOCBP>2024-10362</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Health and Human</EAR>
            <HD>Health and Human Services Department</HD>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>Centers for Medicare &amp; Medicaid Services</P>
            </SEE>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>National Institutes of Health</P>
            </SEE>
        </AGCY>
        <AGCY>
            <EAR>Homeland</EAR>
            <HD>Homeland Security Department</HD>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>Coast Guard</P>
            </SEE>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>Federal Emergency Management Agency</P>
            </SEE>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>U.S. Customs and Border Protection</P>
            </SEE>
        </AGCY>
        <AGCY>
            <EAR>Indian Affairs</EAR>
            <HD>Indian Affairs Bureau</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Liquor Code Amendment:</SJ>
                <SJDENT>
                    <SJDOC>Santa Ana Pueblo, </SJDOC>
                    <PGS>41983-41990</PGS>
                    <FRDOCBP>2024-10525</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Industry</EAR>
            <HD>Industry and Security Bureau</HD>
            <CAT>
                <HD>RULES</HD>
                <DOCENT>
                    <DOC>Additions of Entities to the Entity List, </DOC>
                    <PGS>41886-41895</PGS>
                    <FRDOCBP>2024-10485</FRDOCBP>
                </DOCENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Interior</EAR>
            <HD>Interior Department</HD>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>Geological Survey</P>
            </SEE>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>Indian Affairs Bureau</P>
            </SEE>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>Land Management Bureau</P>
            </SEE>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>National Park Service</P>
            </SEE>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>Reclamation Bureau</P>
            </SEE>
        </AGCY>
        <AGCY>
            <EAR>Internal Revenue</EAR>
            <HD>Internal Revenue Service</HD>
            <CAT>
                <HD>NOTICES</HD>
                <DOCENT>
                    <DOC>Agency Information Collection Activities; Proposals, Submissions, and Approvals, </DOC>
                    <PGS>42056</PGS>
                    <FRDOCBP>2024-10486</FRDOCBP>
                </DOCENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>International Trade Adm</EAR>
            <HD>International Trade Administration</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Antidumping or Countervailing Duty Investigations, Orders, or Reviews:</SJ>
                <SJDENT>
                    <SJDOC>Multilayered Wood Flooring from the People's Republic of China, </SJDOC>
                    <PGS>41939-41941</PGS>
                    <FRDOCBP>2024-10512</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>International Trade Com</EAR>
            <HD>International Trade Commission</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Antidumping or Countervailing Duty Investigations, Orders, or Reviews:</SJ>
                <SJDENT>
                    <SJDOC>Aluminum Lithographic Printing Plates from China and Japan, </SJDOC>
                    <PGS>41993-41995</PGS>
                    <FRDOCBP>2024-10502</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Labor Department</EAR>
            <HD>Labor Department</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Agency Information Collection Activities; Proposals, Submissions, and Approvals:</SJ>
                <SJDENT>
                    <SJDOC>Proximity Detection Systems for Continuous Mining Machines in Underground Coal Mines, </SJDOC>
                    <PGS>41995</PGS>
                    <FRDOCBP>2024-10425</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Registration and Equal Employment Opportunity in Apprenticeship Programs, </SJDOC>
                    <PGS>41995-41996</PGS>
                    <FRDOCBP>2024-10427</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Land</EAR>
            <HD>Land Management Bureau</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Agency Information Collection Activities; Proposals, Submissions, and Approvals:</SJ>
                <SJDENT>
                    <SJDOC>Oil and Gas, or Geothermal Resources: Transfers and Assignments, </SJDOC>
                    <PGS>41990-41991</PGS>
                    <FRDOCBP>2024-10434</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>NASA</EAR>
            <HD>National Aeronautics and Space Administration</HD>
            <CAT>
                <HD>RULES</HD>
                <SJ>Acquisition Regulation:</SJ>
                <SJDENT>
                    <SJDOC>Technical Amendments; Correction, </SJDOC>
                    <PGS>41895-41896</PGS>
                    <FRDOCBP>2024-10499</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Assesment</EAR>
            <HD>National Assessment Governing Board</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Hearings, Meetings, Proceedings, etc.:</SJ>
                <SJDENT>
                    <SJDOC>Committee and Quarterly Board Meetings; Correction, </SJDOC>
                    <PGS>41964</PGS>
                    <FRDOCBP>2024-10505</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>National Institute</EAR>
            <HD>National Institutes of Health</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Hearings, Meetings, Proceedings, etc.:</SJ>
                <SJDENT>
                    <SJDOC>Center for Scientific Review, </SJDOC>
                    <PGS>41969</PGS>
                    <FRDOCBP>2024-10511</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>National Institute of General Medical Sciences, </SJDOC>
                    <PGS>41970</PGS>
                    <FRDOCBP>2024-10496</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>National Institute of Neurological Disorders and Stroke, </SJDOC>
                    <PGS>41970</PGS>
                    <FRDOCBP>2024-10521</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>National Institute on Aging, </SJDOC>
                    <PGS>41970</PGS>
                    <FRDOCBP>2024-10495</FRDOCBP>
                      
                    <FRDOCBP>2024-10497</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>National Oceanic</EAR>
            <HD>National Oceanic and Atmospheric Administration</HD>
            <CAT>
                <HD>RULES</HD>
                <SJ>Fisheries of the Caribbean, Gulf of Mexico, and South Atlantic:</SJ>
                <SJDENT>
                    <SJDOC>Reef Fish Fishery of the Gulf of Mexico; Red Snapper Data Calibrations and Gray Snapper Harvest Levels, </SJDOC>
                    <PGS>41896-41899</PGS>
                    <FRDOCBP>2024-10468</FRDOCBP>
                </SJDENT>
                <SJ>Fisheries of the Northeastern United States:</SJ>
                <SJDENT>
                    <SJDOC>Summer Flounder Fishery; Quota Transfer from North Carolina to Virginia, </SJDOC>
                    <PGS>41899-41900</PGS>
                    <FRDOCBP>2024-10573</FRDOCBP>
                </SJDENT>
            </CAT>
            <CAT>
                <HD>PROPOSED RULES</HD>
                <SJ>Endangered and Threatened Species:</SJ>
                <SJDENT>
                    <SJDOC>Protective Regulations for the Oceanic Whitetip Shark (Carcharhinus longimanus), </SJDOC>
                    <PGS>41917-41924</PGS>
                    <FRDOCBP>2024-10466</FRDOCBP>
                </SJDENT>
            </CAT>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Agency Information Collection Activities; Proposals, Submissions, and Approvals:</SJ>
                <SJDENT>
                    <SJDOC>Deep Seabed Mining Exploration Licenses, </SJDOC>
                    <PGS>41945</PGS>
                    <FRDOCBP>2024-10535</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Documentation of Fish Harvest, </SJDOC>
                    <PGS>41942-41943</PGS>
                    <FRDOCBP>2024-10529</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Fishery Capacity Reduction Program/Buyback Requests, </SJDOC>
                    <PGS>41947</PGS>
                    <FRDOCBP>2024-10530</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>National Marine Sanctuary Permits, </SJDOC>
                    <PGS>41943-41944</PGS>
                    <FRDOCBP>2024-10537</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Resident Perceptions of Offshore Wind Energy Development off the Oregon Coast and along the Gulf of Mexico, </SJDOC>
                    <PGS>41944-41945</PGS>
                    <FRDOCBP>2024-10527</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Transshipment Requirements under the Western and Central Pacific Fisheries Convention Implementation Act, </SJDOC>
                    <PGS>41946</PGS>
                    <FRDOCBP>2024-10534</FRDOCBP>
                </SJDENT>
                <DOCENT>
                    <DOC>Approval of a Boundary Expansion for the Narragansett Bay National Estuarine Research Reserve, </DOC>
                    <PGS>41946</PGS>
                    <FRDOCBP>2024-10462</FRDOCBP>
                </DOCENT>
                <SJ>Taking or Importing of Marine Mammals:</SJ>
                <SJDENT>
                    <SJDOC>Lower Columbia River Dredged Material Management Plan, Oregon and Washington, </SJDOC>
                    <PGS>41941-41942</PGS>
                    <FRDOCBP>2024-10423</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>National Park</EAR>
            <HD>National Park Service</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>National Register of Historic Places:</SJ>
                <SJDENT>
                    <SJDOC>Pending Nominations and Related Actions, </SJDOC>
                    <PGS>41991-41992</PGS>
                    <FRDOCBP>2024-10494</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>National Transportation</EAR>
            <HD>National Transportation Safety Board</HD>
            <CAT>
                <HD>NOTICES</HD>
                <DOCENT>
                    <DOC>Meetings; Sunshine Act, </DOC>
                    <PGS>41996</PGS>
                    <FRDOCBP>2024-10619</FRDOCBP>
                </DOCENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>
                Nuclear Regulatory
                <PRTPAGE P="v"/>
            </EAR>
            <HD>Nuclear Regulatory Commission</HD>
            <CAT>
                <HD>PROPOSED RULES</HD>
                <DOCENT>
                    <DOC>Independent Spent Fuel Storage Installation Security Requirements, </DOC>
                    <PGS>41901-41903</PGS>
                    <FRDOCBP>2024-10480</FRDOCBP>
                </DOCENT>
            </CAT>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Facility Operating and Combined Licenses:</SJ>
                <SJDENT>
                    <SJDOC>Applications and Amendments Involving Proposed No Significant Hazards Considerations, etc., </SJDOC>
                    <PGS>41996-42004</PGS>
                    <FRDOCBP>2024-10034</FRDOCBP>
                </SJDENT>
                <SJ>Permits; Applications, Issuances, etc.:</SJ>
                <SJDENT>
                    <SJDOC>US SFR Owner, LLC, </SJDOC>
                    <PGS>42004</PGS>
                    <FRDOCBP>2024-10474</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Patent</EAR>
            <HD>Patent and Trademark Office</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Agency Information Collection Activities; Proposals, Submissions, and Approvals:</SJ>
                <SJDENT>
                    <SJDOC>Patent Prosecution Highway Program, </SJDOC>
                    <PGS>41948-41950</PGS>
                    <FRDOCBP>2024-10476</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Postal Regulatory</EAR>
            <HD>Postal Regulatory Commission</HD>
            <CAT>
                <HD>NOTICES</HD>
                <DOCENT>
                    <DOC>New Postal Products, </DOC>
                    <PGS>42004-42005</PGS>
                    <FRDOCBP>2024-10463</FRDOCBP>
                </DOCENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Presidential Documents</EAR>
            <HD>Presidential Documents</HD>
            <CAT>
                <HD>PROCLAMATIONS</HD>
                <SJ>Special Observances:</SJ>
                <SJDENT>
                    <SJDOC>Military Spouse Appreciation Day (Proc. 10753), </SJDOC>
                    <PGS>41881-41882</PGS>
                    <FRDOCBP>2024-10639</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Reclamation</EAR>
            <HD>Reclamation Bureau</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Hearings, Meetings, Proceedings, etc.:</SJ>
                <SJDENT>
                    <SJDOC>Colorado River Basin Salinity Control Advisory Council, </SJDOC>
                    <PGS>41992-41993</PGS>
                    <FRDOCBP>2024-10467</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Rural Housing Service</EAR>
            <HD>Rural Housing Service</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Funding Availability:</SJ>
                <SJDENT>
                    <SJDOC>Puerto Rico Rural Partners Network Rural Community Development Initiative, </SJDOC>
                    <PGS>41928-41939</PGS>
                    <FRDOCBP>2024-10363</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Securities</EAR>
            <HD>Securities and Exchange Commission</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Application:</SJ>
                <SJDENT>
                    <SJDOC>John Hancock Multi Asset Credit Fund et al., </SJDOC>
                    <PGS>42009</PGS>
                    <FRDOCBP>2024-10506</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Monachil Credit Income Fund, et al., </SJDOC>
                    <PGS>42009-42010</PGS>
                    <FRDOCBP>2024-10422</FRDOCBP>
                </SJDENT>
                <SJ>Self-Regulatory Organizations; Proposed Rule Changes:</SJ>
                <SJDENT>
                    <SJDOC>Cboe Exchange, Inc., </SJDOC>
                    <PGS>42007-42009</PGS>
                    <FRDOCBP>2024-10432</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Depository Trust Corp., </SJDOC>
                    <PGS>42006</PGS>
                    <FRDOCBP>2024-10429</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>Fixed Income Clearing Corp., </SJDOC>
                    <PGS>42006-42007</PGS>
                    <FRDOCBP>2024-10435</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>National Securities Clearing Corp., </SJDOC>
                    <PGS>42005</PGS>
                    <FRDOCBP>2024-10430</FRDOCBP>
                </SJDENT>
                <SJDENT>
                    <SJDOC>New York Stock Exchange LLC, </SJDOC>
                    <PGS>42007</PGS>
                    <FRDOCBP>2024-10431</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Small Business</EAR>
            <HD>Small Business Administration</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Disaster or Emergency Declaration and Related Determination:</SJ>
                <SJDENT>
                    <SJDOC>Oklahoma, </SJDOC>
                    <PGS>42010</PGS>
                    <FRDOCBP>2024-10436</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>State Department</EAR>
            <HD>State Department</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Agency Information Collection Activities; Proposals, Submissions, and Approvals:</SJ>
                <SJDENT>
                    <SJDOC>Student and Exchange Visitor Information System, </SJDOC>
                    <PGS>42011-42012</PGS>
                    <FRDOCBP>2024-10487</FRDOCBP>
                </SJDENT>
                <DOCENT>
                    <DOC>Sanctions Action, </DOC>
                    <PGS>42010-42049</PGS>
                    <FRDOCBP>2024-10510</FRDOCBP>
                      
                    <FRDOCBP>2024-10509</FRDOCBP>
                </DOCENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Surface Transportation</EAR>
            <HD>Surface Transportation Board</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Requests for Nominations:</SJ>
                <SJDENT>
                    <SJDOC>Railroad-Shipper Transportation Advisory Council, </SJDOC>
                    <PGS>42049-42050</PGS>
                    <FRDOCBP>2024-10493</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Susquehanna</EAR>
            <HD>Susquehanna River Basin Commission</HD>
            <CAT>
                <HD>NOTICES</HD>
                <DOCENT>
                    <DOC>Grandfathering Registration, </DOC>
                    <PGS>42050</PGS>
                    <FRDOCBP>2024-10517</FRDOCBP>
                </DOCENT>
                <DOCENT>
                    <DOC>Hearings, Meetings, Proceedings, etc., </DOC>
                    <PGS>42052</PGS>
                    <FRDOCBP>2024-10520</FRDOCBP>
                </DOCENT>
                <DOCENT>
                    <DOC>Permits; Applications, Issuances, etc., </DOC>
                    <PGS>42051</PGS>
                    <FRDOCBP>2024-10516</FRDOCBP>
                </DOCENT>
                <DOCENT>
                    <DOC>Projects Approved for Consumptive Uses of Water, </DOC>
                    <PGS>42050-42051</PGS>
                    <FRDOCBP>2024-10519</FRDOCBP>
                </DOCENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Trade Representative</EAR>
            <HD>Trade Representative, Office of United States</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Hearings, Meetings, Proceedings, etc.:</SJ>
                <SJDENT>
                    <SJDOC>Annual Review of Country Eligibility for Benefits under the African Growth and Opportunity Act for Calendar Year 2025, </SJDOC>
                    <PGS>42052-42054</PGS>
                    <FRDOCBP>2024-10482</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Transportation Department</EAR>
            <HD>Transportation Department</HD>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>Federal Aviation Administration</P>
            </SEE>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>Federal Motor Carrier Safety Administration</P>
            </SEE>
        </AGCY>
        <AGCY>
            <EAR>Treasury</EAR>
            <HD>Treasury Department</HD>
            <SEE>
                <HD SOURCE="HED">See</HD>
                <P>Internal Revenue Service</P>
            </SEE>
            <CAT>
                <HD>PROPOSED RULES</HD>
                <DOCENT>
                    <DOC>Privacy Act; Exempting a System of Records from Certain Requirements, </DOC>
                    <PGS>41912-41914</PGS>
                    <FRDOCBP>2024-09696</FRDOCBP>
                </DOCENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Customs</EAR>
            <HD>U.S. Customs and Border Protection</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Determination:</SJ>
                <SJDENT>
                    <SJDOC>Battery-Electric Semi-Trucks, </SJDOC>
                    <PGS>41971-41973</PGS>
                    <FRDOCBP>2024-10504</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <AGCY>
            <EAR>Veteran Affairs</EAR>
            <HD>Veterans Affairs Department</HD>
            <CAT>
                <HD>NOTICES</HD>
                <SJ>Agency Information Collection Activities; Proposals, Submissions, and Approvals:</SJ>
                <SJDENT>
                    <SJDOC>Veteran/Beneficiary Claim for Reimbursement of Travel Expenses, </SJDOC>
                    <PGS>42056-42057</PGS>
                    <FRDOCBP>2024-10461</FRDOCBP>
                </SJDENT>
                <SJ>Hearings, Meetings, Proceedings, etc.:</SJ>
                <SJDENT>
                    <SJDOC>Veterans' Family, Caregiver and Survivor Advisory Committee, </SJDOC>
                    <PGS>42060</PGS>
                    <FRDOCBP>2024-10514</FRDOCBP>
                </SJDENT>
                <SJ>Request for Information:</SJ>
                <SJDENT>
                    <SJDOC>Nuclear Medicine Technologist Standard of Practice, </SJDOC>
                    <PGS>42057-42060</PGS>
                    <FRDOCBP>2024-10528</FRDOCBP>
                </SJDENT>
            </CAT>
        </AGCY>
        <PTS>
            <HD SOURCE="HED">Separate Parts In This Issue</HD>
            <HD>Part II</HD>
            <DOCENT>
                <DOC>Environmental Protection Agency, </DOC>
                <PGS>42062-42327</PGS>
                <FRDOCBP>2024-08988</FRDOCBP>
            </DOCENT>
        </PTS>
        <AIDS>
            <HD SOURCE="HED">Reader Aids</HD>
            <P>Consult the Reader Aids section at the end of this issue for phone numbers, online resources, finding aids, and notice of recently enacted public laws.</P>
            <P>To subscribe to the Federal Register Table of Contents electronic mailing list, go to https://public.govdelivery.com/accounts/USGPOOFR/subscriber/new, enter your e-mail address, then follow the instructions to join, leave, or manage your subscription.</P>
        </AIDS>
    </CNTNTS>
    <VOL>89</VOL>
    <NO>94</NO>
    <DATE>Tuesday, May 14, 2024</DATE>
    <UNITNAME>Rules and Regulations</UNITNAME>
    <RULES>
        <RULE>
            <PREAMB>
                <PRTPAGE P="41883"/>
                <AGENCY TYPE="F">DEPARTMENT OF TRANSPORTATION</AGENCY>
                <SUBAGY>Federal Aviation Administration</SUBAGY>
                <CFR>14 CFR Part 97</CFR>
                <DEPDOC>[Docket No. 31544; Amdt. No. 4111]</DEPDOC>
                <SUBJECT>Standard Instrument Approach Procedures, and Takeoff Minimums and Obstacle Departure Procedures; Miscellaneous Amendments</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Aviation Administration (FAA), DOT.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Final rule.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This rule establishes, amends, suspends, or removes Standard Instrument Approach Procedures (SIAPS) and associated Takeoff Minimums and Obstacle Departure procedures (ODPs) for operations at certain airports. These regulatory actions are needed because of the adoption of new or revised criteria, or because of changes occurring in the National Airspace System, such as the commissioning of new navigational facilities, adding new obstacles, or changing air traffic requirements. These changes are designed to provide safe and efficient use of the navigable airspace and to promote safe flight operations under instrument flight rules at the affected airports.</P>
                </SUM>
                <EFFDATE>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This rule is effective May 14, 2024. The compliance date for each SIAP, associated Takeoff Minimums, and ODP is specified in the amendatory provisions.</P>
                    <P>The incorporation by reference of certain publications listed in the regulations is approved by the Director of the Federal Register as of May 14, 2024.</P>
                </EFFDATE>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>Availability of matters incorporated by reference in the amendment is as follows:</P>
                </ADD>
                <HD SOURCE="HD1">For Examination</HD>
                <P>1. U.S. Department of Transportation, Docket Ops-M30. 1200 New Jersey Avenue SE, West Bldg., Ground Floor, Washington, DC 20590-0001.</P>
                <P>2. The FAA Air Traffic Organization Service Area in which the affected airport is located;</P>
                <P>3. The office of Aeronautical Information Services, 6500 South MacArthur Blvd., Oklahoma City, OK 73169 or,</P>
                <P>
                    4. The National Archives and Records Administration (NARA). For information on the availability of this material at NARA, visit 
                    <E T="03">www.archives.gov/federal-register/cfr/ibr-locations</E>
                     or email 
                    <E T="03">fr.inspection@nara.gov.</E>
                </P>
                <HD SOURCE="HD1">Availability</HD>
                <P>
                    All SIAPs and Takeoff Minimums and ODPs are available online free of charge. Visit the National Flight Data Center at 
                    <E T="03">nfdc.faa.gov</E>
                     to register. Additionally, individual SIAP and Takeoff Minimums and ODP copies may be obtained from the FAA Air Traffic Organization Service Area in which the affected airport is located.
                </P>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Thomas J. Nichols, Flight Procedures and Airspace Group, Flight Technologies and Procedures Division, Flight Standards Service, Federal Aviation Administration. Mailing Address: FAA Mike Monroney Aeronautical Center, Flight Procedures and Airspace Group, 6500 South MacArthur Blvd., STB Annex, Bldg. 26, Room 217, Oklahoma City, OK 73099. Telephone (405) 954-1139.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>This rule amends 14 CFR part 97 by establishing, amending, suspending, or removes SIAPS, Takeoff Minimums and/or ODPS. The complete regulatory description of each SIAP and its associated Takeoff Minimums or ODP for an identified airport is listed on FAA form documents which are incorporated by reference in this amendment under 5 U.S.C. 552(a), 1 CFR part 51, and 14 CFR 97.20. The applicable FAA Forms are 8260-3, 8260-4, 8260-5, 8260-15A, 8260-15B, when required by an entry on 8260-15A, and 8260-15C.</P>
                <P>
                    The large number of SIAPs, Takeoff Minimums and ODPs, their complex nature, and the need for a special format make publication in the 
                    <E T="04">Federal Register</E>
                     expensive and impractical. Further, pilots do not use the regulatory text of the SIAPs, Takeoff Minimums or ODPs, but instead refer to their graphic depiction on charts printed by publishers or aeronautical materials. Thus, the advantages of incorporation by reference are realized and publication of the complete description of each SIAP, Takeoff Minimums and ODP listed on FAA form documents is unnecessary. This amendment provides the affected CFR sections and specifies the types of SIAPS, Takeoff Minimums and ODPs with their applicable effective dates. This amendment also identifies the airport and its location, the procedure, and the amendment number.
                </P>
                <HD SOURCE="HD1">Availability and Summary of Material Incorporated by Reference</HD>
                <P>
                    The material incorporated by reference is publicly available as listed in the 
                    <E T="02">ADDRESSES</E>
                     section.
                </P>
                <P>The material incorporated by reference describes SIAPS, Takeoff Minimums and/or ODPs as identified in the amendatory language for part 97 of this final rule.</P>
                <HD SOURCE="HD1">The Rule</HD>
                <P>This amendment to 14 CFR part 97 is effective upon publication of each separate SIAP, Takeoff Minimums and ODP as amended in the transmittal. Some SIAP and Takeoff Minimums and textual ODP amendments may have been issued previously by the FAA in a Flight Data Center (FDC) Notice to Air Missions (NOTAM) as an emergency action of immediate flights safety relating directly to published aeronautical charts.</P>
                <P>The circumstances that created the need for some SIAP and Takeoff Minimums and ODP amendments may require making them effective in less than 30 days. For the remaining SIAPs and Takeoff Minimums and ODPs, an effective date at least 30 days after publication is provided.</P>
                <P>
                    Further, the SIAPs and Takeoff Minimums and ODPs contained in this amendment are based on the criteria contained in the U.S. Standard for Terminal Instrument Procedures (TERPS). In developing these SIAPs and Takeoff Minimums and ODPs, the TERPS criteria were applied to the conditions existing or anticipated at the affected airports. Because of the close and immediate relationship between these SIAPs, Takeoff Minimums and ODPs, and safety in air commerce, I find that notice and public procedure under 5 U.S.C. 553(b) are impracticable and contrary to the public interest and, 
                    <PRTPAGE P="41884"/>
                    where applicable, under 5 U.S.C. 553(d), good cause exists for making some SIAPs effective in less than 30 days.
                </P>
                <P>The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. It, therefore—(1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. For the same reason, the FAA certifies that this amendment will not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.</P>
                <LSTSUB>
                    <HD SOURCE="HED">Lists of Subjects in 14 CFR Part 97</HD>
                    <P>Air Traffic Control, Airports, Incorporation by reference, Navigation (Air).</P>
                </LSTSUB>
                <SIG>
                    <DATED>Issued in Washington, DC, on April 26, 2024.</DATED>
                    <NAME>Thomas J. Nichols,</NAME>
                    <TITLE>Aviation Safety, Flight Standards Service, Manager, Standards Section, Flight Procedures &amp; Airspace Group, Flight Technologies &amp; Procedures Division.</TITLE>
                </SIG>
                <HD SOURCE="HD1">Adoption of the Amendment</HD>
                <P>Accordingly, pursuant to the authority delegated to me, 14 CFR part 97 is amended by establishing, amending, suspending, or removing Standard Instrument Approach Procedures and/or Takeoff Minimums and Obstacle Departure Procedures effective at 0901 UTC on the dates specified, as follows:</P>
                <PART>
                    <HD SOURCE="HED">PART 97—STANDARD INSTRUMENT APPROACH PROCEDURES</HD>
                </PART>
                <REGTEXT TITLE="14" PART="97">
                    <AMDPAR>1. The authority citation for part 97 continues to read as follows:</AMDPAR>
                    <AUTH>
                        <HD SOURCE="HED">Authority:</HD>
                        <P> 49 U.S.C. 106(f), 106(g), 40103, 40106, 40113, 40114, 40120, 44502, 44514, 44701, 44719, 44721-44722.</P>
                    </AUTH>
                </REGTEXT>
                <REGTEXT TITLE="14" PART="97">
                    <AMDPAR>2. Part 97 is amended to read as follows:</AMDPAR>
                    <EXTRACT>
                        <HD SOURCE="HD1">Effective 13 June 2024</HD>
                        <FP SOURCE="FP-1">Searcy, AR, SRC, ILS OR LOC RWY 1, Orig-B</FP>
                        <FP SOURCE="FP-1">Jefferson, GA, JCA, VOR RWY 35, Amdt 4</FP>
                        <FP SOURCE="FP-1">Paris, ID, 1U7, RNAV (GPS) RWY 10, Amdt 1</FP>
                        <FP SOURCE="FP-1">Paris, ID, 1U7, RNAV (GPS) RWY 28, Amdt 1</FP>
                        <FP SOURCE="FP-1">Artesia, NM, ATS, RNAV (GPS) RWY 13, Amdt 2A</FP>
                        <FP SOURCE="FP-1">Artesia, NM, ATS, RNAV (GPS) RWY 22, Amdt 1D</FP>
                        <FP SOURCE="FP-1">Artesia, NM, ATS, RNAV (GPS) RWY 31, Amdt 2A</FP>
                        <FP SOURCE="FP-1">Reno, NV, KRNO, RNAV (GPS) Y RWY 35L, Amdt 1A</FP>
                        <FP SOURCE="FP-1">Shirley, NY, HWV, RNAV (GPS) RWY 15, Orig-B</FP>
                        <FP SOURCE="FP-1">Shirley, NY, HWV, RNAV (GPS) RWY 33, Orig-B</FP>
                        <FP SOURCE="FP-1">Clarksville, TN, KCKV, Takeoff Minimums and Obstacle DP, Amdt 2A</FP>
                        <HD SOURCE="HD1">Effective 11 July 2024</HD>
                        <FP SOURCE="FP-1">Kalskag, AK, KLG/PALG, RNAV (GPS) RWY 7, Amdt 1A</FP>
                        <FP SOURCE="FP-1">Kalskag, AK, PALG, RNAV (GPS)-A, Amdt 1A</FP>
                        <FP SOURCE="FP-1">King Salmon, AK, PAKN, Takeoff Minimums and Obstacle DP, Amdt 2</FP>
                        <FP SOURCE="FP-1">Northway, AK, PAOR, NORTHWAY ONE, Graphic DP</FP>
                        <FP SOURCE="FP-1">Northway, AK, ORT/PAOR, RNAV (GPS) RWY 6, Amdt 1</FP>
                        <FP SOURCE="FP-1">Northway, AK, ORT/PAOR, RNAV (GPS) RWY 24, Amdt 2</FP>
                        <FP SOURCE="FP-1">Northway, AK, PAOR, Takeoff Minimums and Obstacle DP, Amdt 3</FP>
                        <FP SOURCE="FP-1">Northway, AK, ORT/PAOR, VOR-A, Amdt 2</FP>
                        <FP SOURCE="FP-1">Colt, AR, DRP, RNAV (GPS) RWY 18, Amdt 1</FP>
                        <FP SOURCE="FP-1">Colt, AR, DRP, RNAV (GPS) RWY 36, Amdt 1</FP>
                        <FP SOURCE="FP-1">Pine Bluff, AR, PBF, RNAV (GPS) RWY 18, Amdt 1E</FP>
                        <FP SOURCE="FP-1">Pine Bluff, AR, PBF, RNAV (GPS) RWY 36, Amdt 1E</FP>
                        <FP SOURCE="FP-1">Victorville, CA, VCV, RNAV (GPS) RWY 3, Orig</FP>
                        <FP SOURCE="FP-1">Watsonville, CA, WVI, RNAV (GPS) RWY 2, Amdt 3</FP>
                        <FP SOURCE="FP-1">Zephyrhills, FL, ZPH, RNAV (GPS) RWY 1, Amdt 2</FP>
                        <FP SOURCE="FP-1">Zephyrhills, FL, KZPH, Takeoff Minimums and Obstacle DP, Amdt 3</FP>
                        <FP SOURCE="FP-1">Pella, IA, PEA, NDB RWY 34, Amdt 7D, CANCELED</FP>
                        <FP SOURCE="FP-1">Sandpoint, ID, SZT, LOC-A, Amdt 2A, CANCELED</FP>
                        <FP SOURCE="FP-1">Sandpoint, ID, SZT, RNAV (GPS) Y RWY 2, Orig</FP>
                        <FP SOURCE="FP-1">Sandpoint, ID, SZT, RNAV (GPS) Z RWY 2, Orig</FP>
                        <FP SOURCE="FP-1">Twin Falls, ID, TWF, RNAV (GPS) RWY 8, Amdt 3</FP>
                        <FP SOURCE="FP-1">Jonesboro, LA, F88, RNAV (GPS) RWY 18, Orig-D</FP>
                        <FP SOURCE="FP-1">Jonesboro, LA, F88, RNAV (GPS) RWY 36, Orig-D</FP>
                        <FP SOURCE="FP-1">Morristown, TN, MOR, NDB RWY 5, Amdt 5D, CANCELED</FP>
                        <FP SOURCE="FP-1">Morristown, TN, MOR, SDF RWY 5, Amdt 5D, CANCELED</FP>
                        <FP SOURCE="FP-1">Clarksville, VA, W63, RNAV (GPS)-B, Orig-A</FP>
                        <FP SOURCE="FP-1">Mineral Point, WI, MRJ, RNAV (GPS) RWY 4, Amdt 1B</FP>
                        <FP SOURCE="FP-1">Mineral Point, WI, MRJ, RNAV (GPS) RWY 11, Amdt 1B</FP>
                        <FP SOURCE="FP-1">Mineral Point, WI, MRJ, RNAV (GPS) RWY 22, Amdt 1B</FP>
                        <FP SOURCE="FP-1">Mineral Point, WI, MRJ, RNAV (GPS) RWY 29, Amdt 1B</FP>
                    </EXTRACT>
                </REGTEXT>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10322 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4910-13-P</BILCOD>
        </RULE>
        <RULE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF TRANSPORTATION</AGENCY>
                <SUBAGY>Federal Aviation Administration</SUBAGY>
                <CFR>14 CFR Part 97</CFR>
                <DEPDOC>[Docket No. 31545; Amdt. No. 4112]</DEPDOC>
                <SUBJECT>Standard Instrument Approach Procedures, and Takeoff Minimums and Obstacle Departure Procedures; Miscellaneous Amendments</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Aviation Administration (FAA), DOT.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Final rule.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This rule amends, suspends, or removes Standard Instrument Approach Procedures (SIAPs) and associated Takeoff Minimums and Obstacle Departure Procedures for operations at certain airports. These regulatory actions are needed because of the adoption of new or revised criteria, or because of changes occurring in the National Airspace System, such as the commissioning of new navigational facilities, adding new obstacles, or changing air traffic requirements. These changes are designed to provide for the safe and efficient use of the navigable airspace and to promote safe flight operations under instrument flight rules at the affected airports.</P>
                </SUM>
                <EFFDATE>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This rule is effective May 14, 2024. The compliance date for each SIAP, associated Takeoff Minimums, and ODP is specified in the amendatory provisions.</P>
                    <P>The incorporation by reference of certain publications listed in the regulations is approved by the Director of the Federal Register as of May 14, 2024.</P>
                </EFFDATE>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>Availability of matter incorporated by reference in the amendment is as follows:</P>
                </ADD>
                <HD SOURCE="HD1">For Examination</HD>
                <P>1. U.S. Department of Transportation, Docket Ops-M30, 1200 New Jersey Avenue SE, West Bldg., Ground Floor, Washington, DC 20590-0001;</P>
                <P>2. The FAA Air Traffic Organization Service Area in which the affected airport is located;</P>
                <P>3. The office of Aeronautical Information Services, 6500 South MacArthur Blvd, Oklahoma City, OK 73169 or,</P>
                <P>4. The National Archives and Records Administration (NARA).</P>
                <P>
                    For information on the availability of this material at NARA, visit 
                    <E T="03">www.archives.gov/federal-register/cfr/ibr-locations</E>
                     or email 
                    <E T="03">fr.inspection@nara.gov.</E>
                    <PRTPAGE P="41885"/>
                </P>
                <HD SOURCE="HD1">Availability</HD>
                <P>
                    All SIAPs and Takeoff Minimums and ODPs are available online free of charge. Visit the National Flight Data Center online at 
                    <E T="03">nfdc.faa.gov</E>
                     to register. Additionally, individual SIAP and Takeoff Minimums and ODP copies may be obtained from the FAA Air Traffic Organization Service Area in which the affected airport is located.
                </P>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Thomas J. Nichols, Flight Procedures and Airspace Group, Flight Technologies and Procedures Division, Flight Standards Service, Federal Aviation Administration. Mailing Address: FAA Mike Monroney Aeronautical Center, Flight Procedures and Airspace Group, 6500 South MacArthur Blvd., STB Annex, Bldg. 26, Room 217, Oklahoma City, OK 73099. Telephone: (405) 954-1139.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    This rule amends 14 CFR part 97 by amending the referenced SIAPs. The complete regulatory description of each SIAP is listed on the appropriate FAA Form 8260, as modified by the National Flight Data Center (NFDC)/Permanent Notice to Air Missions (P-NOTAM), and is incorporated by reference under 5 U.S.C. 552(a), 1 CFR part 51, and 14 CFR 97.20. The large number of SIAPs, their complex nature, and the need for a special format make their verbatim publication in the 
                    <E T="04">Federal Register</E>
                     expensive and impractical. Further, pilots do not use the regulatory text of the SIAPs, but refer to their graphic depiction on charts printed by publishers of aeronautical materials. Thus, the advantages of incorporation by reference are realized and publication of the complete description of each SIAP contained on FAA form documents is unnecessary. This amendment provides the affected CFR sections, and specifies the SIAPs and Takeoff Minimums and ODPs with their applicable effective dates. This amendment also identifies the airport and its location, the procedure and the amendment number.
                </P>
                <HD SOURCE="HD1">Availability and Summary of Material Incorporated by Reference</HD>
                <P>
                    The material incorporated by reference is publicly available as listed in the 
                    <E T="02">ADDRESSES</E>
                     section.
                </P>
                <P>The material incorporated by reference describes SIAPs, Takeoff Minimums and ODPs as identified in the amendatory language for part 97 of this final rule.</P>
                <HD SOURCE="HD1">The Rule</HD>
                <P>This amendment to 14 CFR part 97 is effective upon publication of each separate SIAP and Takeoff Minimums and ODP as amended in the transmittal. For safety and timeliness of change considerations, this amendment incorporates only specific changes contained for each SIAP and Takeoff Minimums and ODP as modified by FDC permanent NOTAMs.</P>
                <P>The SIAPs and Takeoff Minimums and ODPs, as modified by FDC permanent NOTAM, and contained in this amendment are based on criteria contained in the U.S. Standard for Terminal Instrument Procedures (TERPS). In developing these changes to SIAPs and Takeoff Minimums and ODPs, the TERPS criteria were applied only to specific conditions existing at the affected airports. All SIAP amendments in this rule have been previously issued by the FAA in a FDC NOTAM as an emergency action of immediate flight safety relating directly to published aeronautical charts.</P>
                <P>The circumstances that created the need for these SIAP and Takeoff Minimums and ODP amendments require making them effective in less than 30 days.</P>
                <P>Because of the close and immediate relationship between these SIAPs, Takeoff Minimums and ODPs, and safety in air commerce, I find that notice and public procedure under 5 U.S.C. 553(b) are impracticable and contrary to the public interest and, where applicable, under 5 U.S.C. 553(d), good cause exists for making these SIAPs effective in less than 30 days.</P>
                <P>The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. It, therefore—(1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. For the same reason, the FAA certifies that this amendment will not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.</P>
                <LSTSUB>
                    <HD SOURCE="HED">List of Subjects in 14 CFR Part 97</HD>
                    <P>Air Traffic Control, Airports, Incorporation by reference, Navigation (Air).</P>
                </LSTSUB>
                <SIG>
                    <DATED>Issued in Washington, DC, on April 26, 2024.</DATED>
                    <NAME>Thomas J. Nichols,</NAME>
                    <TITLE>Aviation Safety, Flight Standards Service, Manager, Standards Section, Flight Procedures &amp; Airspace Group, Flight Technologies &amp; Procedures Division.</TITLE>
                </SIG>
                <HD SOURCE="HD1">Adoption of the Amendment</HD>
                <P>Accordingly, pursuant to the authority delegated to me, 14 CFR part 97 is amended by amending Standard Instrument Approach Procedures and Takeoff Minimums and ODPs, effective at 0901 UTC on the dates specified, as follows:</P>
                <PART>
                    <HD SOURCE="HED">PART 97—STANDARD INSTRUMENT APPROACH PROCEDURES</HD>
                </PART>
                <REGTEXT TITLE="14" PART="97">
                    <AMDPAR>1. The authority citation for part 97 continues to read as follows:</AMDPAR>
                    <AUTH>
                        <HD SOURCE="HED">Authority: </HD>
                        <P>49 U.S.C. 106(f), 106(g), 40103, 40106, 40113, 40114, 40120, 44502, 44514, 44701, 44719, 44721-44722.</P>
                    </AUTH>
                </REGTEXT>
                <REGTEXT TITLE="14" PART="97">
                    <AMDPAR>2. Part 97 is amended to read as follows:</AMDPAR>
                    <P>By amending: § 97.23 VOR, VOR/DME, VOR or TACAN, and VOR/DME or TACAN; § 97.25 LOC, LOC/DME, LDA, LDA/DME, SDF, SDF/DME; § 97.27 NDB, NDB/DME; § 97.29 ILS, ILS/DME, MLS, MLS/DME, MLS/RNAV; § 97.31 RADAR SIAPs; § 97.33 RNAV SIAPs; and § 97.35 COPTER SIAPs, Identified as follows:</P>
                    <EXTRACT>
                        <HD SOURCE="HD2">* * * Effective Upon Publication</HD>
                    </EXTRACT>
                    <GPOTABLE COLS="7" OPTS="L2,tp0,i1" CDEF="xs60,xls32,r50,r50,12,12,r50">
                        <TTITLE> </TTITLE>
                        <BOXHD>
                            <CHED H="1">
                                AIRAC
                                <LI>date</LI>
                            </CHED>
                            <CHED H="1">State</CHED>
                            <CHED H="1">City</CHED>
                            <CHED H="1">Airport name</CHED>
                            <CHED H="1">
                                FDC
                                <LI>No.</LI>
                            </CHED>
                            <CHED H="1">
                                FDC
                                <LI>date</LI>
                            </CHED>
                            <CHED H="1">Procedure name</CHED>
                        </BOXHD>
                        <ROW>
                            <ENT I="01">13-Jun-24</ENT>
                            <ENT>AR</ENT>
                            <ENT>Searcy</ENT>
                            <ENT>Searcy Rgnl</ENT>
                            <ENT>4/0361</ENT>
                            <ENT>3/22/2024</ENT>
                            <ENT>RNAV (GPS) RWY 19, Amdt 1A.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">13-Jun-24</ENT>
                            <ENT>OH</ENT>
                            <ENT>Zanesville</ENT>
                            <ENT>Zanesville Muni</ENT>
                            <ENT>4/3168</ENT>
                            <ENT>4/8/2024</ENT>
                            <ENT>RNAV (GPS) RWY 4, Orig.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">13-Jun-24</ENT>
                            <ENT>OH</ENT>
                            <ENT>Zanesville</ENT>
                            <ENT>Zanesville Muni</ENT>
                            <ENT>4/3169</ENT>
                            <ENT>4/8/2024</ENT>
                            <ENT>ILS OR LOC RWY 22, Amdt 2.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">13-Jun-24</ENT>
                            <ENT>OH</ENT>
                            <ENT>Zanesville</ENT>
                            <ENT>Zanesville Muni</ENT>
                            <ENT>4/3170</ENT>
                            <ENT>4/8/2024</ENT>
                            <ENT>RNAV (GPS) RWY 22, Orig-A.</ENT>
                        </ROW>
                        <ROW>
                            <PRTPAGE P="41886"/>
                            <ENT I="01">13-Jun-24</ENT>
                            <ENT>MI</ENT>
                            <ENT>Boyne Falls</ENT>
                            <ENT>Boyne Mountain</ENT>
                            <ENT>4/7894</ENT>
                            <ENT>4/8/2024</ENT>
                            <ENT>RNAV (GPS) RWY 17, Orig-B.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">13-Jun-24</ENT>
                            <ENT>WI</ENT>
                            <ENT>Ashland</ENT>
                            <ENT>John F Kennedy Meml</ENT>
                            <ENT>4/8096</ENT>
                            <ENT>4/9/2024</ENT>
                            <ENT>LOC RWY 2, Amdt 1B.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">13-Jun-24</ENT>
                            <ENT>VA</ENT>
                            <ENT>Farmville</ENT>
                            <ENT>Farmville Rgnl</ENT>
                            <ENT>4/8938</ENT>
                            <ENT>4/10/2024</ENT>
                            <ENT>RNAV (GPS) RWY 21, Orig-C.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">13-Jun-24</ENT>
                            <ENT>FL</ENT>
                            <ENT>Pompano Beach</ENT>
                            <ENT>Pompano Beach Airpark</ENT>
                            <ENT>4/8941</ENT>
                            <ENT>4/10/2024</ENT>
                            <ENT>LOC RWY 15, Amdt 5A.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">13-Jun-24</ENT>
                            <ENT>IN</ENT>
                            <ENT>Marion</ENT>
                            <ENT>Marion Muni—Mckinney Fld</ENT>
                            <ENT>4/9949</ENT>
                            <ENT>3/21/2024</ENT>
                            <ENT>RNAV (GPS) RWY 15, Amdt 1.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">13-Jun-24</ENT>
                            <ENT>IN</ENT>
                            <ENT>Marion</ENT>
                            <ENT>Marion Muni—Mckinney Fld</ENT>
                            <ENT>4/9952</ENT>
                            <ENT>3/21/2024</ENT>
                            <ENT>RNAV (GPS) RWY 33, Orig-D.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">13-Jun-24</ENT>
                            <ENT>IN</ENT>
                            <ENT>Marion</ENT>
                            <ENT>Marion Muni—Mckinney Fld</ENT>
                            <ENT>4/9953</ENT>
                            <ENT>3/21/2024</ENT>
                            <ENT>VOR RWY 15, Amdt 10F.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">13-Jun-24</ENT>
                            <ENT>IN</ENT>
                            <ENT>Marion</ENT>
                            <ENT>Marion Muni—Mckinney Fld</ENT>
                            <ENT>4/9955</ENT>
                            <ENT>3/21/2024</ENT>
                            <ENT>ILS OR LOC RWY 4, Amdt 8A.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">13-Jun-24</ENT>
                            <ENT>IN</ENT>
                            <ENT>Marion</ENT>
                            <ENT>Marion Muni—Mckinney Fld</ENT>
                            <ENT>4/9956</ENT>
                            <ENT>3/21/2024</ENT>
                            <ENT>RNAV (GPS) RWY 22, Amdt 1.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">13-Jun-24</ENT>
                            <ENT>IN</ENT>
                            <ENT>Marion</ENT>
                            <ENT>Marion Muni—Mckinney Fld</ENT>
                            <ENT>4/9976</ENT>
                            <ENT>3/21/2024</ENT>
                            <ENT>RNAV (GPS) RWY 4, Amdt 1.</ENT>
                        </ROW>
                    </GPOTABLE>
                </REGTEXT>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10323 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4910-13-P</BILCOD>
        </RULE>
        <RULE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF COMMERCE</AGENCY>
                <SUBAGY>Bureau of Industry and Security</SUBAGY>
                <CFR>15 CFR Part 744</CFR>
                <DEPDOC>[Docket No. 240507-0130]</DEPDOC>
                <RIN>RIN 0694-AJ62</RIN>
                <SUBJECT>Additions of Entities to the Entity List</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Bureau of Industry and Security, Department of Commerce.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Final rule.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>In this final rule, the Bureau of Industry and Security (BIS) amends the Export Administration Regulations (EAR) by adding 37 entities under 37 entries to the Entity List. These entries are listed on the Entity List under the destinations of the People's Republic of China (China) and have been determined by the U.S. Government to be acting contrary to the national security or foreign policy interests of the United States.</P>
                </SUM>
                <EFFDATE>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This rule is effective May 9, 2024.</P>
                </EFFDATE>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Chair, End-User Review Committee, Office of the Assistant Secretary for Export Administration, Bureau of Industry and Security, Department of Commerce, Phone: (202) 482-5991, Email: 
                        <E T="03">ERC@bis.doc.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">Background</HD>
                <P>
                    The Entity List (supplement no. 4 to part 744 of the EAR (15 CFR parts 730 through 774)) identifies entities for which there is reasonable cause to believe, based on specific and articulable facts, that the entities have been involved, are involved, or pose a significant risk of being or becoming involved in activities contrary to the national security or foreign policy interests of the United States, pursuant to § 744.11(b). The EAR impose additional license requirements on, and limit the availability of, most license exceptions for exports, reexports, and transfers (in-country) when a listed entity is a party to the transaction. The license review policy for each listed entity is identified in the “License Review Policy” column on the Entity List, and the impact on the availability of license exceptions is described in the relevant 
                    <E T="04">Federal Register</E>
                     document that added the entity to the Entity List. BIS places entities on the Entity List pursuant to parts 744 (Control Policy: End-User and End-Use Based) and 746 (Embargoes and Other Special Controls) of the EAR.
                </P>
                <P>The End-User Review Committee (ERC), composed of representatives of the Departments of Commerce (Chair), State, Defense, Energy and, where appropriate, the Treasury, makes all decisions regarding additions to, removals from, or other modifications to the Entity List. The ERC makes all decisions to add an entry to the Entity List by majority vote and makes all decisions to remove or modify an entry by unanimous vote.</P>
                <HD SOURCE="HD2">Additions to the Entity List</HD>
                <P>The ERC determined to add Beijing BDStar Navigation Co., Ltd.; Beijing Ruidakang Technology Co., Ltd.; Beijing Tianhaida Technology Co., Ltd.; Chengdu Day Communication Technology Co., Ltd.; Hexin Xingtong Technology (Beijing) Co., Ltd.; Suzhou Telecom Electric Plant Co., Ltd.; TaiYuan EFT Equipment Manufacturing Co., Ltd.; and Xi'an Hengda Microwave Technology Development Co., Ltd., all under the destination of China, to the Entity List. These entities are being added for their support to the High Altitude Balloon that overflew the United States in February 2023. This activity is contrary to the national security and foreign policy interests of the United States under § 744.11 of the EAR.</P>
                <P>The ERC determined to add Beijing Leiki Defense Technology Co., Ltd.; GEOVIS Technology Co., Ltd.; and Zhongke Xingtu Space Technology Co., Ltd., all under the destination of China, to the Entity List for their connections to companies that support China's High Altitude Balloon program. This activity is contrary to the national security and foreign policy interests of the United States under § 744.11 of the EAR.</P>
                <P>
                    The ERC determined to add AEE Shenzhen Yidian Aviation Technology Co., Ltd.; Beijing Zhongshang Dingsheng Mechanical and Electrical Equipment Co., Ltd.; Chengdu Zongheng Automation Technology Co., Ltd.; and Shenzhen Yidian Technology Co., Ltd., all under the destination of China, to the Entity List. These entities are added for acquiring and attempting to acquire U.S.-origin items, applicable to unmanned aerial vehicles, to be used by Chinese military entities. In addition, AEE Shenzhen Yidian Aviation Technology Co., Ltd., Beijing Zhongshang Dingsheng Mechanical and Electrical Equipment Co., Ltd., and Shenzhen Yidian Technology Co., Ltd. have been involved in the shipment of controlled items to Russia since Russia's invasion of Ukraine in February 2022. This activity is contrary to the national security and foreign policy interests of 
                    <PRTPAGE P="41887"/>
                    the United States under § 744.11 of the EAR.
                </P>
                <P>The ERC has determined to add Beijing Academy of Quantum Information Sciences; CETC Chip Technology Co., Ltd.; Ceyear Technologies Co., Ltd.; China Electronics Technology Group Corporation 16th Research Institute; China Electronics Technology Group Corporation 32nd Research Institute; China Electronics Technology Group Corporation 36th Research Institute; China Electronics Technology Group Corporation 41st Research Institute; China Electronics Technology Group Corporation 45th Research Institute; China Electronics Technology Group Corporation Electronic Equipment Group Co., Ltd.; Chinese Academy of Sciences, Center for Excellence in Quantum Information and Quantum Physics; Chinese Academy of Sciences, Institute of Physics; Chinese Academy of Sciences, Key Laboratory for Quantum Information; Chinese Academy of Sciences' Shanghai Institute of Microsystem and Information Technology; CSIC Pride (Nanjing) Cryogenic Technology Co., Ltd.; Hefei National Laboratory for Quantum Information Science; Jinan Institute of Quantum Technology; Origin Quantum Computing Technology (Hefei) Co., Ltd.; Quantum Science and Technology Yangtze River Delta Industrial Innovation Center; Shanghai Center for Quantum Science Research; Shenzhen Institute of Quantum Science and Engineering; United Microelectronics Center Co., Ltd.; and University of Science and Technology of China to the Entity List, all under the destination of China. These entities are added for acquiring and attempting to acquire U.S.-origin items in support of advancing China's quantum technology capabilities, which has serious ramifications for U.S. national security given the military applications of quantum technologies. Outside of advancing China's quantum technology capabilities, China Electronics Technology Group Corporation Electronic Equipment Group Co., Ltd. and the University of Science and Technology of China are also involved in advancing China's nuclear program development. In addition, CSIC Pride (Nanjing) Cryogenic Technology Co., Ltd.; China Electronics Technology Group Corporation 45th Research Institute; and Ceyear Technologies Co., Ltd. have been involved in the shipment of controlled items to Russia since Russia's invasion of Ukraine in February 2022. These activities are contrary to the national security and foreign policy interests of the United States under § 744.11 of the EAR.</P>
                <P>For the reasons described above, this final rule adds the following 37 entities under 37 entries to the Entity List and includes, where appropriate, aliases:</P>
                <HD SOURCE="HD1">China</HD>
                <P>• AEE Shenzhen Yidian Aviation Technology Co., Ltd.,</P>
                <P>• Beijing Academy of Quantum Information Sciences,</P>
                <P>• Beijing BDStar Navigation Co., Ltd,</P>
                <P>• Beijing Leike Defense Technology Co., Ltd.,</P>
                <P>• Beijing Ruidakang Technology Co., Ltd.,</P>
                <P>• Beijing Tianhaida Technology Co., Ltd.,</P>
                <P>• Beijing Zhongshang Dingsheng Mechanical and Electrical Equipment Co., Ltd.,</P>
                <P>• CETC Chip Technology Co., Ltd.,</P>
                <P>• Ceyear Technologies Co., Ltd.,</P>
                <P>• Chengdu Day Communication Technology Co., Ltd.,</P>
                <P>• Chengdu Zongheng Automation Technology Co., Ltd.,</P>
                <P>• China Electronics Technology Group Corporation 16th Research Institute,</P>
                <P>• China Electronics Technology Group Corporation 32nd Research Institute,</P>
                <P>• China Electronics Technology Group Corporation 36th Research Institute,</P>
                <P>• China Electronics Technology Group Corporation 41st Research Institute,</P>
                <P>• China Electronics Technology Group Corporation 45th Research Institute,</P>
                <P>• China Electronics Technology Group Corporation Electronic Equipment Group Co., Ltd.,</P>
                <P>• Chinese Academy of Science, Center for Excellence in Quantum Information and Quantum Physics,</P>
                <P>• Chinese Academy of Sciences, Institute of Physics,</P>
                <P>• Chinese Academy of Sciences, Key Laboratory for Quantum Information,</P>
                <P>• Chinese Academy of Sciences' Shanghai Institute of Microsystem and Information Technology,</P>
                <P>• CSIC Pride (Nanjing) Cryogenic Technology Co., Ltd.,</P>
                <P>• GEOVIS Technology Co., Ltd.,</P>
                <P>• Hefei National Laboratory for Quantum Information Science,</P>
                <P>• Hexin Xingtong Technology (Beijing) Co., Ltd.,</P>
                <P>• Jinan Institute of Quantum Technology,</P>
                <P>• Origin Quantum Computing Technology (Hefei) Co., Ltd.,</P>
                <P>• Quantum Science and Technology Yangtze River Delta Industrial Innovation Center,</P>
                <P>• Shanghai Center for Quantum Science Research,</P>
                <P>• Shenzhen Institute of Quantum Science and Engineering,</P>
                <P>• Shenzhen Yidian Technology Co., Ltd.,</P>
                <P>• Suzhou Telecom Electric Plant Co., Ltd.,</P>
                <P>• TaiYuan EFT Equipment Manufacturing Co., Ltd.,</P>
                <P>• United Microelectronics Center Co., Ltd.,</P>
                <P>• University of Science and Technology of China,</P>
                <P>
                    • Xi'an Hengda Microwave Technology Development Co., Ltd., 
                    <E T="03">and</E>
                </P>
                <P>• Zhongke Xingtu Space Technology Co., Ltd.</P>
                <HD SOURCE="HD2">Savings Clause</HD>
                <P>For the changes being made in this final rule, shipments of items removed from eligibility for a License Exception or export, reexport, or transfer (in-country) without a license (NLR) as a transfer (in-country), on May 9, 2024, pursuant to actual orders for export, reexport, or transfer (in-country) to or within a foreign destination, may proceed to that destination under the previous eligibility for a License Exception or export, reexport, or transfer (in-country) without a license (NLR) before June 10, 2024. Any such items not actually exported, reexported, or transferred (in-country) before midnight, on June 10, 2024, require a license in accordance with this final rule.</P>
                <HD SOURCE="HD1">Export Control Reform Act of 2018</HD>
                <P>On August 13, 2018, the President signed into law the John S. McCain National Defense Authorization Act for Fiscal Year 2019, which included the Export Control Reform Act of 2018 (ECRA) (50 U.S.C. 4801-4852). ECRA provides the legal basis for BIS's principal authorities and serves as the authority under which BIS issues this rule.</P>
                <HD SOURCE="HD1">Rulemaking Requirements</HD>
                <P>1. This rule has been determined to be not significant for purposes of Executive Order 12866, as amended by Executive Order 14094.</P>
                <P>
                    2. Notwithstanding any other provision of law, no person is required to respond to or be subject to a penalty for failure to comply with a collection of information, subject to the requirements of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 
                    <E T="03">et seq.</E>
                    ) (PRA), unless that collection of information displays a currently valid Office of Management and Budget (OMB) Control Number. This regulation involves an information collection 
                    <PRTPAGE P="41888"/>
                    approved by OMB under control number 0694-0088, Simplified Network Application Processing System. BIS does not anticipate a change to the burden hours associated with this collection as a result of this rule. Information regarding the collection, including all supporting materials, can be accessed at 
                    <E T="03">https://www.reginfo.gov/public/do/PRAMain.</E>
                </P>
                <P>3. This rule does not contain policies with federalism implications as that term is defined in Executive Order 13132.</P>
                <P>4. Pursuant to section 1762 of the Export Control Reform Act of 2018, this action is exempt from the Administrative Procedure Act (5 U.S.C. 553) requirements for notice of proposed rulemaking, opportunity for public participation, and delay in effective date.</P>
                <P>
                    5. Because a notice of proposed rulemaking and an opportunity for public comment are not required to be given for this rule by 5 U.S.C. 553, or by any other law, the analytical requirements of the Regulatory Flexibility Act, 5 U.S.C. 601, 
                    <E T="03">et seq.,</E>
                     are not applicable. Accordingly, no regulatory flexibility analysis is required, and none has been prepared.
                </P>
                <LSTSUB>
                    <HD SOURCE="HED">List of Subjects in 15 CFR Part 744</HD>
                    <P>Exports, Reporting and recordkeeping requirements, Terrorism.</P>
                </LSTSUB>
                <P>Accordingly, part 744 of the Export Administration Regulations (15 CFR parts 730 through 774) is amended as follows:</P>
                <PART>
                    <HD SOURCE="HED">PART 744—CONTROL POLICY: END-USER AND END-USE BASED</HD>
                </PART>
                <REGTEXT TITLE="15" PART="744">
                    <AMDPAR>1. The authority citation for 15 CFR part 744 continues to read as follows:</AMDPAR>
                    <AUTH>
                        <HD SOURCE="HED">Authority:</HD>
                        <P>
                            50 U.S.C. 4801-4852; 50 U.S.C. 4601 
                            <E T="03">et seq.;</E>
                             50 U.S.C. 1701 
                            <E T="03">et seq.;</E>
                             22 U.S.C. 3201 
                            <E T="03">et seq.;</E>
                             42 U.S.C. 2139a; 22 U.S.C. 7201 
                            <E T="03">et seq.;</E>
                             22 U.S.C. 7210; E.O. 12058, 43 FR 20947, 3 CFR, 1978 Comp., p. 179; E.O. 12851, 58 FR 33181, 3 CFR, 1993 Comp., p. 608; E.O. 12938, 59 FR 59099, 3 CFR, 1994 Comp., p. 950; E.O. 13026, 61 FR 58767, 3 CFR, 1996 Comp., p. 228; E.O. 13099, 63 FR 45167, 3 CFR, 1998 Comp., p. 208; E.O. 13222, 66 FR 44025, 3 CFR, 2001 Comp., p. 783; E.O. 13224, 66 FR 49079, 3 CFR, 2001 Comp., p. 786; Notice of November 8, 2022, 87 FR 68015, 3 CFR, 2022 Comp., p. 563; Notice of September 7, 2023, 88 FR 62439 (September 11, 2023).
                        </P>
                    </AUTH>
                </REGTEXT>
                <REGTEXT TITLE="15" PART="744">
                    <AMDPAR>
                        2. Supplement no. 4 to part 744 is amended under CHINA, PEOPLE'S REPUBLIC OF by adding, in alphabetical order, entries for “AEE Shenzhen Yidian Aviation Technology Co., Ltd.;” “Beijing Academy of Quantum Information Sciences;” “Beijing BDStar Navigation Co., Ltd;” “Beijing Leike Defense Technology Co., Ltd.;” “Beijing Ruidakang Technology Co., Ltd.;” “Beijing Tianhaida Technology Co., Ltd.;” “Beijing Zhongshang Dingsheng Mechanical and Electrical Equipment Co., Ltd.;” “CETC Chip Technology Co., Ltd.;” “Ceyear Technologies Co., Ltd.;” “Chengdu Day Communication Technology Co., Ltd.;” “Chengdu Zongheng Automation Technology Co., Ltd.;” “China Electronics Technology Group Corporation 16th Research Institute;” “China Electronics Technology Group Corporation 32nd Research Institute;” “China Electronics Technology Group Corporation 36th Research Institute;” “China Electronics Technology Group Corporation 41st Research Institute;” “China Electronics Technology Group Corporation 45th Research Institute;” “China Electronics Technology Group Corporation Electronic Equipment Group Co., Ltd.;” “Chinese Academy of Science, Center for Excellence in Quantum Information and Quantum Physics;” “Chinese Academy of Sciences, Institute of Physics;” “Chinese Academy of Sciences, Key Laboratory for Quantum Information;” “Chinese Academy of Sciences' Shanghai Institute of Microsystem and Information Technology;” “CSIC Pride (Nanjing) Cryogenic Technology Co., Ltd.;” “GEOVIS Technology Co., Ltd.;” “Hefei National Laboratory for Quantum Information Science;” “Hexin Xingtong Technology (Beijing) Co., Ltd.;” “Jinan Institute of Quantum Technology;” “Origin Quantum Computing Technology (Hefei) Co., Ltd.;” “Quantum Science and Technology Yangtze River Delta Industrial Innovation Center;” “Shanghai Center for Quantum Science Research;” “Shenzhen Institute of Quantum Science and Engineering;” “Shenzhen Yidian Technology Co., Ltd.;” “Suzhou Telecom Electric Plant Co., Ltd.;” “TaiYuan EFT Equipment Manufacturing Co., Ltd.;” “United Microelectronics Center Co., Ltd.;” “University of Science and Technology of China;” “Xi'an Hengda Microwave Technology Development Co., Ltd.;” 
                        <E T="03">and</E>
                         “Zhongke Xingtu Space Technology Co., Ltd.” to read as follows:
                    </AMDPAR>
                    <HD SOURCE="HD1">Supplement No. 4 to Part 744—Entity List</HD>
                    <STARS/>
                    <GPOTABLE COLS="5" OPTS="L1,nj,tp0,p7,7/8,i1" CDEF="xs60,xl75,r50,r50,r50">
                        <TTITLE> </TTITLE>
                        <BOXHD>
                            <CHED H="1">Country</CHED>
                            <CHED H="1">Entity</CHED>
                            <CHED H="1">
                                License
                                <LI>requirement</LI>
                            </CHED>
                            <CHED H="1">
                                License
                                <LI>review policy</LI>
                            </CHED>
                            <CHED H="1">
                                <E T="02">Federal Register</E>
                                <LI>citation</LI>
                            </CHED>
                        </BOXHD>
                        <ROW>
                            <ENT I="22"> </ENT>
                        </ROW>
                        <ROW RUL="s">
                            <ENT I="28">*         *         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">CHINA, PEOPLE'S REPUBLIC OF</ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                AEE Shenzhen Yidian Aviation Technology Co., Ltd., a.k.a., the following two aliases:
                                <LI>
                                    —Shenzhen AEE Aviation Technology Co., Ltd.; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—Shenzhen One Electric Aviation Technology Co., Ltd.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Floor 18, Building A, Shenzhen International Innovation Center (Futian Technology Plaza), No. 1006 Shennan Avenue, Xintian Community, Huafu Street, Futian District, Shenzhen, China; 
                                <E T="03">and</E>
                                 3rd Floor, Building 3, Wanda Industrial Park, West Side of Songbai Highway, Tangtou Community, Shiyan Street, Baoan District, Shenzhen, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <PRTPAGE P="41889"/>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Beijing Academy of Quantum Information Sciences, a.k.a., the following three aliases:
                                <LI>—BAQIS;</LI>
                                <LI>
                                    —Beijing Institute of Quantum Information Science; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—Beijing Quantum Institute.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Building 3, West District, No. 10 Northwest Wangdong Road, Haidian District, Beijing, China; 
                                <E T="03">and</E>
                                 Building A, International and Regional Collaborative Innovation Center, Zhongguancun Software Park Phase II, Haidian District, Beijing, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Beijing BDStar Navigation Co., Ltd. a.k.a. the following one alias:
                                <LI>—Beijing Beidou Star Navigation Technology Co., Ltd.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                No. 7 Fengxian East Road, Haidian District, Beijing, China;
                                <E T="03"> and</E>
                                 Second Floor, South Building, Beidou Star Building, No. 7 Fengxian East Road, Haidian District, Beijing, China; 
                                <E T="03">and</E>
                                 C1, 36 West Ring Road, Beijing, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Beijing Leike Defense Technology Co., Ltd., a.k.a., the following two aliases:
                                <LI>
                                    —Rayco Defense, 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—Reco Defense.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Floor 6, Building 5, Yard No. 2, West Third Ring North Road, Haidian District, Beijing, China;
                                <E T="03"> and</E>
                                 South of Jianhua Road, Jiandong Village, Lijia Town, Wujin District, Changzhou, Jiangsu, China; 
                                <E T="03">and</E>
                                 3rd Floor, Building 5, Lu Xun Cultural and Creative Park, No. 6 Yuanda South Street, Haidian District, Beijing, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Beijing Ruidakang Technology Co., Ltd., a.k.a., the following two aliases:
                                <LI>
                                    —Beijing Ruida Kang Technology Co., Ltd.; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—RuiDaKangDP.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>Room 301, 3rd Floor, Comprehensive Building, East Courtyard, Houtun Village, Xiaoying Road, Qinghe, Haidian District, Beijing, China.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Beijing Tianhaida Technology Co., Ltd.
                                <LI>
                                    No. 9 Fengde East Road, Yongfeng Industrial Base, Haidian District, Beijing, China; 
                                    <E T="03">and</E>
                                     Room 4038, 4th Floor, Building 2, Yard 9, Fengde East Road, Haidian District, Beijing, China;
                                    <E T="03"> and</E>
                                     Room 4034, Floor 4, Building 2, Yard 9, Fengde East Road, Haidian District, Beijing, China.;
                                    <E T="03"> and</E>
                                     No. 5011, Commerce, Floor 5, Building A10, Runqianqiujiayuan, Haidian District, Beijing, 100039, China; 
                                    <E T="03">and</E>
                                     Floor 4-5, Building 2, No. 9, Fengde East Road, Yongfeng Industrial Base, Haidian District, Beijing, China.
                                </LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Beijing Zhongshang Dingsheng Mechanical and Electrical Equipment Co., Ltd., a.k.a., the following four aliases:
                                <LI>—China Optics Best Technology;</LI>
                                <LI>—CoBTec Ltd.;</LI>
                                <LI>
                                    —Beijing CBT Optics Equipment Co., Ltd.; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—China Business Dingsheng.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <PRTPAGE P="41890"/>
                            <ENT I="22"> </ENT>
                            <ENT>
                                No. 1301-02, Floor 13, Building 3, District 1, No. 29 Kechuang 13th Street, Beijing Economic and Technological Development Zone, Beijing, China; 
                                <E T="03">and</E>
                                 Building 3, No. 1, Tiansha Road, Tangxia Town, Dongguan City, Guangdong Province, China; 
                                <E T="03">and</E>
                                 Tower 3 of TianTongTai Valley, 13th Street of Kechuang, ETD District, Beijing, 100176, China; 
                                <E T="03">and</E>
                                 No. 1501-03, Building C, Tiantontai Science and Technology Financial Valley, No. 29, Kechuang 13th Street, Tongzhou District, Beijing, China; 
                                <E T="03">and</E>
                                 Room 503, Building 8, Timecourt No. 6 Yard Shuguangxili, Beijing, Chaoyang District, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                CETC Chip Technology Co., Ltd., a.k.a., the following seven aliases:
                                <LI>—CETC 24;</LI>
                                <LI>—Sichuan Solid Circuit Research Institute;</LI>
                                <LI>—CETC 44;</LI>
                                <LI>—CETC Chongqing Sound and Optoelectronics Co., Ltd.;</LI>
                                <LI>—Chongqing Optoelectronics Technology Research Institute;</LI>
                                <LI>
                                    —CETC 26; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—Dianke Chip Group.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                No. 14, Nanping Huayuan Road, Economic and Technological Development Zone, Chongqing, China; 
                                <E T="03">and</E>
                                 No. 5-12 Yuhan Road, Shuitu Hi-Tech Industrial Zone, Chongqing, China; 
                                <E T="03">and</E>
                                 No. 23, Xiyong Avenue, Shapingba District, Chongqing, China; 
                                <E T="03">and</E>
                                 Sichuan Institute of Piezoelec &amp; Acousto-Optic Technology 14#, Chongqing, China; 
                                <E T="03">and</E>
                                 Room 301, No. 3, Lane 5005, Shenjiang Road, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Ceyear Technologies Co., Ltd., a.k.a., the following five aliases:
                                <LI>—CETC Instrument Co., Ltd.;</LI>
                                <LI>
                                    —CETC Ceyear Technologies Co., Ltd.; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—Zhongdianke Ceyear Technology;</LI>
                                <LI>—China Electronics Technology Instruments Co., Ltd; and</LI>
                                <LI>—CETI.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                No. 98 Xiangjiang Road, Huangdao District, Qingdao, Shandong, China; 
                                <E T="03">and</E>
                                 Room 606, Floor 6, Building 16, No. 23, Shijingshan Road, Shijingshan District, Beijing, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Chengdu Day Communication Technology Co., Ltd., a.k.a., the following one alias:
                                <LI>—Chengdu Huari Communication Technology Co., Ltd.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                No. 130, Wuxing 4th Road, Wuhou District, Chengdu, Sichuan, China; 
                                <E T="03">and</E>
                                 No. 6 East Sect. 3 Wuke Road, Chengdu, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Chengdu Zongheng Automation Technology Co., Ltd., a.k.a., the following six aliases:
                                <LI>—JOUAV;</LI>
                                <LI>—Zongheng Automation Technology Co., Ltd.;</LI>
                                <LI>—Zongheng Co., Ltd.;</LI>
                                <LI>—Chengdu JOUAV Automation Tech Co.,Ltd.;</LI>
                                <LI>
                                    —Zongheng Technology; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—Chengdu JOUAV Dapeng Tech Co., Ltd.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <PRTPAGE P="41891"/>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Floor 11, Area A, Building 3, Jingronghui, No. 200, Tianfu 5th Street, High-Tech Zone, Chengdu, China; 
                                <E T="03">and</E>
                                 7th Floor, Area A, Building 6, No. 200, Tianfu 5th Street, Chengdu High-Tech Zone, Pilot Free Trade Zone, Chengdu, China; 
                                <E T="03">and</E>
                                 Room 801-805, Floor 8, Area A, Building 3, No. 200, Tianfu 5th Street, Chengdu High-Tech Zone, Pilot Free Trade Zone, Chengdu, China; 
                                <E T="03">and</E>
                                 Room 3a, Area A, Jingrong International Plaza, No. 200, Tianfu 5th Street, Wuhou District, Chengdu, Sichuan Province, China; 
                                <E T="03">and</E>
                                 Unit 701-702,7/F, Grand Tech Centre, No. 8 On Ping Street, Shatin, Hong Kong; 
                                <E T="03">and</E>
                                 6A-7F, Jingrong Intl Plaza, 5th Tianfu St., No. 200 Hi-Tech District, Chengdu City, China; 
                                <E T="03">and</E>
                                 3A-8F, Jingrong Innovation Hub No 200, 5th Tianfu St., Chengdu, 610041, China; 
                                <E T="03">and</E>
                                 Building No. 9, Huafu Avenue, 4th Section, No.777, Chengdu, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                China Electronics Technology Group Corporation 16th Research Institute, a.k.a., the following two aliases:
                                <LI>
                                    —CETC 16; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—Hefei Institute of Low-Temperature Electronics.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                No. 439 Suixi Road, Luyang District, Hefei China; 
                                <E T="03">and</E>
                                 No. 658, Wangjiang West Road, Hefei, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                China Electronics Technology Group Corporation 32nd Research Institute, a.k.a., the following three aliases:
                                <LI>—CETC 32;</LI>
                                <LI>
                                    —CETC Digital Technology (Group) Co., Ltd.; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—East China Institute of Computing Technology</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                No. 63 Chengliu Highway, Jiading District, Shanghai, China; 
                                <E T="03">and</E>
                                 No. 1485, Jialuo Road, Jiading District, Shanghai, China; 
                                <E T="03">and</E>
                                 Room 812, Bank of East Asia No. 66 Huayuan Shiqiao Road, Pudong, Shanghai, China; 
                                <E T="03">and</E>
                                 Room 220, Second Floor, 101, 1st to 3rd floors, Building 5, No. 7 Rongda Road, Chaoyang District, Beijing, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                China Electronics Technology Group Corporation 36th Research Institute, a.k.a., the following three aliases:
                                <LI>—CETC 36;</LI>
                                <LI>
                                    —CTRONICS Technology Group; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—Jiangnan Electronic Communications Research Institute (JNECR).</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                No. 387, Hongxing Road, Jiaxing, China; 
                                <E T="03">and</E>
                                 Box 9, Jiaxing, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                China Electronics Technology Group Corporation 41st Research Institute, a.k.a., the following two aliases:
                                <LI>
                                    —CETC 41; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—East China Institute of Electronic Measuring Instruments.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                No. 726, Changzheng Road, Bengbu, China; 
                                <E T="03">and</E>
                                 No. 98, Xiangjiang Road, Huangdao District, Qingdao, China; 
                                <E T="03">and</E>
                                 No. 800, Changsheng Road, Bengbu, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                China Electronics Technology Group Corporation 45th Research Institute, a.k.a., the following three aliases:
                                <LI>—CETC 45;</LI>
                                <LI>
                                    —Beijing Semiconductor Special Equipment Research Institute; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—Beijing CETC Electronic Equipment Co., Ltd.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>No. 1, Taihe 3rd Street, Tongzhou District, Beijing, China.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <PRTPAGE P="41892"/>
                            <ENT I="22"> </ENT>
                            <ENT>
                                China Electronics Technology Group Corporation Electronic Equipment Group Co., Ltd., a.k.a., the following three aliases:
                                <LI>—CETC Equipment Subgroup;</LI>
                                <LI>
                                    —Dianke Equipment; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—CETC-E.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Room 2001, Floor 20, Building B, Building 1, No. 19 Ronghua Middle Road, Beijing Economic and Technological Development Zone, Beijing, China; 
                                <E T="03">and</E>
                                 7th Floor, West Annex Building, Building 1, Nord Center, No. 128 South Fourth Ring West Road, Fengtai District, Beijing, China; 
                                <E T="03">and</E>
                                 7/F, West Wing of No.1 Noble Center, 128 West Road of South 4th Ring Road., Fengtai District, Beijing, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Chinese Academy of Science, Center for Excellence in Quantum Information and Quantum Physics, a.k.a., the following three aliases:
                                <LI>—Collaborative Innovation Center for Frontiers of Quantum Information and Quantum Technology;</LI>
                                <LI>
                                    —Quantum Innovation Institute; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—Quantum 2011.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                No. 96, Jinzhai Road, Hefei, China; 
                                <E T="03">and</E>
                                 Wangjiang West Road, Shushan District, Hefei, China; 
                                <E T="03">and</E>
                                 No. 62, Taihu Road, Baohe District, Hefei, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Chinese Academy of Sciences, Institute of Physics, a.k.a., the following one alias:
                                <LI>—IOPCAS.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                No. 8, Zhongguancun South Third Street, Haidian District, Beijing, China; 
                                <E T="03">and</E>
                                 No. 8, Zhongguancun South 3rd Street, between the 3rd and 4th rings of Zhongguancun Street, Haidian District, Beijing, China; 
                                <E T="03">and</E>
                                 No. 5, Xizai Road, Huairou District, Beijing, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Chinese Academy of Sciences, Key Laboratory for Quantum Information, a.k.a., the following one alias:
                                <LI>—KLQI.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>East District, University of Science and Technology of China, No. 96, Jinzhai Road, Baohe District, Hefei, China.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Chinese Academy of Sciences' Shanghai Institute of Microsystem and Information Technology, a.k.a., the following three aliases:
                                <LI>—SIMIT;</LI>
                                <LI>
                                    —Shanghai Institute of Metallurgy; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—SIMIT-CAS.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Building 8, No. 865, Changning Road, Changning District, Shanghai, China; 
                                <E T="03">and</E>
                                 Building A, No. 1455, Pingcheng Road, Jiading District, Shanghai, China; 
                                <E T="03">and</E>
                                 Jiading Park, No. 235, Chengbei Road, China; 
                                <E T="03">and</E>
                                 No. 800, Yishan Road, Xuhui District, Shanghai, China; 
                                <E T="03">and</E>
                                 Room 613, Building 8, No 865 Changning Road, Shanghai, China; 
                                <E T="03">and</E>
                                 Room 604, Xinweijiayuan, 1455 Pincheng Road, Shanghai, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                CSIC Pride (Nanjing) Cryogenic Technology Co., Ltd., a.k.a., the following three aliases:
                                <LI>—Pride Cryogenics;</LI>
                                <LI>
                                    —Easycool; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—CSIC Pengli (Nanjing) Ultra-low Temperature Technology Co., Ltd.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>No. 32 Changqing Street, Jiangning Development Zone, Nanjing, China.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                GEOVIS Technology Co., Ltd., a.k.a., the following two aliases:
                                <LI>
                                    —Zhongke Xingtu Co., Ltd.; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—Zhongke Star Chart Co., Ltd.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <PRTPAGE P="41893"/>
                            <ENT I="22"> </ENT>
                            <ENT>
                                1A-4 Xingtu Building, National Geographic Information Technology Industrial Park, No. 2 Airport East Road, Airport Economic Core Area, Shunyi District, Beijing, China.;
                                <E T="03"> and</E>
                                 No. 2, Jichang E. Road, Linkong Jingji Hexin District, Shunyi District Beijing, Beijing, 101399, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Hefei National Laboratory for Quantum Information Science, a.k.a., the following one alias:
                                <LI>—NLQIS.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>5099 Wang Jiang West Road, Shushan District, Hefei, China.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Hexin Xingtong Technology (Beijing) Co., Ltd., a.k.a., the following two aliases:
                                <LI>
                                    —Unicorecomm, 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—Hexinxingtong Technology (Beijing) Co., Ltd.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                3rd Floor, Beidouxingtong Building, No. 7 Fengxian East Road, Haidian District, Beijing, China; 
                                <E T="03">and</E>
                                 3F Building 8, No. 912 Bi Bo Road, Shanghai, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Jinan Institute of Quantum Technology, a.k.a., the following one alias:
                                <LI>—JIQT.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                No. 747, Shunhua Road, High-tech Zone, Jinan, Shandong, China; 
                                <E T="03">and</E>
                                 Room 508-509, Area A, Block B, Qilu Software Park Building, Jinan, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Origin Quantum Computing Technology (Hefei) Co., Ltd., a.k.a., the following four aliases:
                                <LI>—Origin Quantum;</LI>
                                <LI>—Origin QC;</LI>
                                <LI>
                                    —Hefei Origin Quantum Computing Technology Co., Ltd.; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—Hefei Benyuan Quantum Computing Technology Co., Ltd.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Building D8, Zhongan Chuanggu Science and Technology Park, No. 900, Wangjiang West Road, Shushan District, Hefei, China; 
                                <E T="03">and</E>
                                 6th Floor, Building E2, Phase II, Innovation Industrial Park, No. 2800, Chuangxin Avenue, High-tech Zone, Hefei, China; 
                                <E T="03">and</E>
                                 No. 104, Building 21, Maker Mansion, No. 2039, South Section of Tianfu Ave., Tianfu New District, Chengdu, China; 
                                <E T="03">and</E>
                                 Room 101, Floor 2-6, Building 5, East District, No. 10 Northwest Wangdong Road, Haidian District, Beijing, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Quantum Science and Technology Yangtze River Delta Industrial Innovation Center, a.k.a., the following one alias:
                                <LI>—Suzhou Institute of Quantum Science and Technology of China Academy of Electronics Sciences.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>Room 101, Block 9C, Start-Up Zone, Yangtze River Delta International R&amp;D Community, No. 286, Qinglonggang Road, Xiangcheng District, Suzhou, China.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Shanghai Center for Quantum Science Research, a.k.a., the following three aliases:
                                <LI>—SRCQS;</LI>
                                <LI>
                                    —Shanghai Institute for Advanced Studies Center for Quantum Engineering; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—USTC Shanghai.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>99 Xiupu Road, Shanghai, China.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Shenzhen Institute of Quantum Science and Engineering, a.k.a., the following one alias:
                                <LI>—SIQSE.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>No. 1088 Xueyuan Avenue, Nanshan District, Shenzhen, China.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <PRTPAGE P="41894"/>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Shenzhen Yidian Technology Co., Ltd., a.k.a., the following three aliases:
                                <LI>—Shenzhen AEE Technology Co., Ltd.;</LI>
                                <LI>
                                    —Shenzhen Love Wireless Technology Co., Ltd.; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—Ace Electronics Enterprise.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                10B-1, Block B, Modern Window Building, Huaqiang North Road, Futian District, Shenzhen, China; 
                                <E T="03">and</E>
                                 AEE Hi-Tech Park Songbai Road, Shiyan Town, Shenzhen, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Suzhou Telecom Electric Plant Co., Ltd. a.k.a., the following one alias:
                                <LI>—Suzhou Telecom Motor Factory Co., Ltd.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>No. 482, Xujiang Road, Suzhou, Jiangsu, China.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                TaiYuan EFT Equipment Manufacturing Co., Ltd., a.k.a., the following two aliases:
                                <LI>
                                    —Taiyuan Yifu Equipment Manufacturing Co., Ltd.; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—Taiyuan Efort Equipment Manufacturing Co., Ltd.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                3rd Floor, University Science and Technology Pioneer Park, Taiyuan High-tech Zone, Taiyuan, Shanxi, China; 
                                <E T="03">and</E>
                                 4th Floor, Wanli Technology Office Building, No. 9 Changzhi West Lane, Taiyuan Xuefu Park, Shanxi Comprehensive Reform Demonstration Zone, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                United Microelectronics Center Co., Ltd., a.k.a., the following two aliases:
                                <LI>
                                    —CUMEC; 
                                    <E T="03">and</E>
                                </LI>
                                <LI>—UMEC.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                No. 2, No. 28, Xiyuan 1st Road, Shapingba District, Chongqing, China; 
                                <E T="03">and</E>
                                 No. 20, Xiyuan South Street, Shapingba District, Chongqing, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                University of Science and Technology of China, a.k.a., the following one alias:
                                <LI>—USTC.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                East Campus, No.96, JinZhai Road, Baohe District, Hefei, China; 
                                <E T="03">and</E>
                                 West Campus, No. 443, Huangshan Road, Shushan District, Hefei, China; 
                                <E T="03">and</E>
                                 South Campus, No. 1129 Huizhou Avenue, Baohe District, Hefei, China; 
                                <E T="03">and</E>
                                 No. 100, Fuxing Road, Shushan District, Hefei, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>Xi'an Hengda Microwave Technology Development Co., Ltd.</ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                No. 485 Feitian Road, Aerospace Base, Xi'an, China, 710100; 
                                <E T="03">and</E>
                                 Room 2302, Building 4 OuFengYuan, Chang'an South Road, Xian, Shaanxi Province, China.
                            </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>
                                Zhongke Xingtu Space Technology Co., Ltd., a.k.a., the following one alias:
                                <LI>—Zhongke Starmap Space Technology Co., Ltd.</LI>
                            </ENT>
                            <ENT>For all items subject to the EAR. (See § 744.11 of the EAR)</ENT>
                            <ENT>Presumption of denial</ENT>
                            <ENT>89 FR [INSERT FR PAGE NUMBER May 14, 2024].</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                            <ENT>Floor 9, Block B, Huihang Plaza, Middle Section of Hangtuo Road, National Civil Aerospace Industry Base, Xi'an, Shaanxi, China.</ENT>
                        </ROW>
                        <ROW RUL="s">
                            <ENT I="22"> </ENT>
                            <ENT A="03">*         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="28">*         *         *         *         *         *         *</ENT>
                        </ROW>
                    </GPOTABLE>
                </REGTEXT>
                <PRTPAGE P="41895"/>
                <STARS/>
                <SIG>
                    <NAME>Thea D. Rozman Kendler,</NAME>
                    <TITLE>Assistant Secretary for Export Administration.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10485 Filed 5-9-24; 11:15 am]</FRDOC>
            <BILCOD>BILLING CODE 3510-33-P</BILCOD>
        </RULE>
        <RULE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Coast Guard</SUBAGY>
                <CFR>33 CFR Part 147</CFR>
                <DEPDOC>[Docket No. USCG-2023-0277]</DEPDOC>
                <RIN>RIN 1625-AA00</RIN>
                <SUBJECT>Safety Zone; Vineyard Wind 1 Wind Farm Project Area, Outer Continental Shelf, Lease OCS-A 0501, Offshore Massachusetts, Atlantic Ocean</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Coast Guard, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Temporary interim rule; correction.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>
                        The Coast Guard published a temporary interim rule in the 
                        <E T="04">Federal Register</E>
                         on May 2, 2024, concerning several safety zones offshore of Martha's Vineyard. That document contained an incorrect phone number. This document corrects that phone number.
                    </P>
                </SUM>
                <EFFDATE>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This correction is effective May 14, 2024. Comments on the temporary interim rule (89 FR 35709) are still due on or before July 31, 2024.</P>
                </EFFDATE>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        For information about this document call or email Mr. Craig Lapiejko, Waterways Management, at Coast Guard First District, telephone 866-842-1560, email 
                        <E T="03">craig.d.lapiejko@uscg.mil.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">Correction</HD>
                <P>
                    In the 
                    <E T="04">Federal Register</E>
                     of May 2, 2024, in FR Doc.2024-09538, on page 89 FR 35709, in the first column, in the 
                    <E T="02">FOR FURTHER INFORMATION CONTACT SECTION</E>
                    , the phone number, “617-603-8592”, is corrected to read: “866-842-1560”. This was done to correct an improperly listed phone number and ensure that interested persons can get in touch with our point of contact.
                </P>
                <SIG>
                    <DATED>Dated: May 8, 2024.</DATED>
                    <NAME>James E. McLeod,</NAME>
                    <TITLE>Acting Office Chief, Office of Regulations and Administrative Law.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10481 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9110-04-P</BILCOD>
        </RULE>
        <RULE>
            <PREAMB>
                <AGENCY TYPE="N">FEDERAL MARITIME COMMISSION</AGENCY>
                <CFR>46 CFR Part 541</CFR>
                <DEPDOC>[Docket No. FMC-2022-0066]</DEPDOC>
                <RIN>RIN 3072-AC90</RIN>
                <SUBJECT>Demurrage and Detention Billing Requirements</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Maritime Commission.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Final rule; announcement of effective date.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>
                        The Federal Maritime Commission (FMC) received approval from the Office of Management and Budget (OMB) for an information collection request associated with the final rule for Demurrage and Detention Billing Requirements. This rule announces the effective date for the requirements concerning contents of demurrage and detention invoices. In the final rule published February 26, 2024, we stated we would publish a document in the 
                        <E T="04">Federal Register</E>
                         (FR) announcing the effective date of the collection-of-information related sections upon OMB approval. This rule establishes May 28, 2024, as the effective date of the relevant provisions.
                    </P>
                </SUM>
                <EFFDATE>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The amendments adding 46 CFR 541.6 (instruction 2) and 541.99 (instruction 3), published on February 26, 2024 (89 FR 14330), are effective on May 28, 2024.</P>
                </EFFDATE>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        To view background documents or comments received, you may use the Federal eRulemaking Portal at 
                        <E T="03">www.regulations.gov</E>
                         under Docket No. FMC-2022-0066.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        David Eng, Secretary; Phone: (202) 523-5725; Email: 
                        <E T="03">Secretary@fmc.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>On February 26, 2024, in accordance with the Ocean Shipping Reform Act of 2022, the Federal Maritime Commission published the final rule, “Demurrage and Detention Billing Requirements” that requires common carriers and marine terminal operators to include specific minimum information on demurrage and detention invoices, outlines certain detention and demurrage billing practices, and sets timeframes for insuring invoices, disputing charges with the billing party, and resolving disputes.</P>
                <P>
                    The final rule contained two provisions, 46 CFR 541.6 and 541.99, that were delayed indefinitely, pending information collection approval from OMB under the Paperwork Reduction Act of 1995, 44 U.S.C. 3501-3520. On April 16, 2024, OMB, Office of Information and Regulatory Affairs, approved the information collection requirements with OMB Control Number 3072-0073.
                    <SU>1</SU>
                    <FTREF/>
                     Accordingly, FMC announces that 46 CFR 541.6 and 541.99 are effective May 28, 2024.
                </P>
                <FTNT>
                    <P>
                        <SU>1</SU>
                         The notice of action is available at 
                        <E T="03">https://www.reginfo.gov/public/do/PRAViewICR?ref_nbr=202404-3072-002#.</E>
                    </P>
                </FTNT>
                <LSTSUB>
                    <HD SOURCE="HED">List of Subjects in 46 CFR Part 541</HD>
                    <P>Common carriers, Demurrage and detention, Exports, Imports, Marine terminal operators.</P>
                </LSTSUB>
                <P>For the reasons set forth in the preamble, FMC amends 46 CFR part 541 as follows:</P>
                <PART>
                    <HD SOURCE="HED">PART 541—DEMURRAGE AND DETENTION</HD>
                </PART>
                <REGTEXT TITLE="46" PART="541">
                    <AMDPAR>1. The authority citation for part 541 continues to read as follows:</AMDPAR>
                    <AUTH>
                        <HD SOURCE="HED">Authority:</HD>
                        <P>5 U.S.C. 553; 46 U.S.C. 40101, 40102, 40307, 40501-40503, 41101-41106, 40901-40904, and 46105; and 46 CFR 515.23.</P>
                    </AUTH>
                </REGTEXT>
                <REGTEXT TITLE="46" PART="541">
                    <AMDPAR>2. Revise § 541.99 to read as follows:</AMDPAR>
                    <SECTION>
                        <SECTNO>§ 541.99</SECTNO>
                        <SUBJECT>OMB control number assigned pursuant to the Paperwork Reduction Act.</SUBJECT>
                        <P>The Commission has received Office of Management and Budget approval for this collection of information pursuant to the Paperwork Reduction Act of 1995, as amended. The valid control number for this collection of information is 3072-0073.</P>
                    </SECTION>
                </REGTEXT>
                <SIG>
                    <DATED>Dated: May 9, 2024.</DATED>
                    <P>By the Commission.</P>
                    <NAME>David Eng,</NAME>
                    <TITLE>Secretary.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10515 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 6730-02-P</BILCOD>
        </RULE>
        <RULE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF DEFENSE</AGENCY>
                <AGENCY TYPE="O">GENERAL SERVICES ADMINISTRATION</AGENCY>
                <AGENCY TYPE="O">NATIONAL AERONAUTICS AND SPACE ADMINISTRATION</AGENCY>
                <CFR>48 CFR Part 1</CFR>
                <DEPDOC>[FAC 2024-05; Item II; Docket No. FAR-2024-0052; Sequence No. 1]</DEPDOC>
                <SUBJECT>Federal Acquisition Regulation; Technical Amendments; Correction</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Department of Defense (DoD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Final rule; correction.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>
                        DoD, GSA, and NASA are issuing a correction to FAC 2024-05; Technical Amendments (Item II), which 
                        <PRTPAGE P="41896"/>
                        was published in the 
                        <E T="04">Federal Register</E>
                         on April 22, 2024. This correction makes an update to an OMB number that was recently revised.
                    </P>
                </SUM>
                <EFFDATE>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Effective May 22, 2024.</P>
                </EFFDATE>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Ms. Lois Mandell, Regulatory Secretariat Division (MVCB), at 202-501-4755 or 
                        <E T="03">GSARegSec@gsa.gov.</E>
                         Please cite FAC 2024-05, Technical Amendments; Correction.
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>DoD, GSA, and NASA are correcting an OMB control number under part 1, for section 1.106, published at 89 FR 30252, on April 22, 2024.</P>
                <HD SOURCE="HD1">Correction</HD>
                <P>
                    In FR Doc. 2024-07932, published in the 
                    <E T="04">Federal Register</E>
                     at 89 FR 30252, on April 22, 2024, make the following correction:
                </P>
                <SECTION>
                    <SECTNO>1.106</SECTNO>
                    <SUBJECT>[Corrected]</SUBJECT>
                </SECTION>
                <REGTEXT TITLE="48" PART="1">
                    <AMDPAR>1. On page 30252, in the second column, in section 1.106, in the FAR segment entry of “52.204-10(d)(2) and (3)”, the OMB control No. of “3090-0292” is corrected to read “9000-0177”.</AMDPAR>
                </REGTEXT>
                <SIG>
                    <NAME>William F. Clark,</NAME>
                    <TITLE>Director, Office of Government-wide Acquisition Policy, Office of Acquisition Policy, Office of Government-wide Policy.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10499 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 6820-EP-P</BILCOD>
        </RULE>
        <RULE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF COMMERCE</AGENCY>
                <SUBAGY>National Oceanic and Atmospheric Administration</SUBAGY>
                <CFR>50 CFR Part 622</CFR>
                <DEPDOC>[Docket No. 240508-0133]</DEPDOC>
                <RIN>RIN 0648-BM56</RIN>
                <SUBJECT>Fisheries of the Caribbean, Gulf of Mexico, and South Atlantic; Reef Fish Fishery of the Gulf of Mexico; Red Snapper Data Calibrations and Gray Snapper Harvest Levels</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Final rule.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>NMFS issues regulations to implement management measures described in a framework action under the Fishery Management Plan for the Reef Fish Resources of the Gulf of Mexico (FMP), as prepared by the Gulf of Mexico (Gulf) Fishery Management Council (Council). This final rule modifies the ratios used to set the state-specific red snapper private angling component annual catch limits (ACLs) for Alabama, Florida, and Mississippi and modifies each of these state's private angling component ACLs based on the new ratios. In addition, this final rule modifies the stock ACL for gray snapper in the Gulf exclusive economic zone (EEZ). The purposes of this final rule are to update the state specific private angling component calibration ratios and ACLs to provide a more accurate estimate of state landings for red snapper management and to revise gray snapper catch limits with updated scientific information to continue to achieve optimum yield (OY) for the stock.</P>
                </SUM>
                <EFFDATE>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This final rule is effective June 13, 2024.</P>
                </EFFDATE>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Electronic copies of the framework action, which include an environmental assessment, regulatory impact review, and a Regulatory Flexibility Act (RFA) analysis, may be obtained from the Southeast Regional Office website at 
                        <E T="03">https://www.fisheries.noaa.gov/action/red-snapper-data-calibrations-and-catch-limit-modifications.</E>
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Dan Luers, Southeast Regional Office, NMFS, telephone: 727-824-5305, email: 
                        <E T="03">daniel.luers@noaa.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The Gulf reef fish fishery, which includes both red snapper and gray snapper, is managed under the FMP. The Council prepared the FMP, which the Secretary of Commerce approved, and NMFS implements the FMP through regulations at 50 CFR part 622 under the authority of the Magnuson-Stevens Fishery Conservation and Management Act (Magnuson-Stevens Act).</P>
                <HD SOURCE="HD1">Background</HD>
                <P>The Magnuson-Stevens Act requires NMFS and regional fishery management councils to prevent overfishing and to achieve, on a continuing basis, the optimum yield (OY) from federally managed fish stocks to ensure that fishery resources are managed for the greatest overall benefit to the nation, particularly with respect to providing food production and recreational opportunities and protecting marine ecosystems.</P>
                <P>On January 17, 2024, NMFS published a proposed rule for the framework action and requested public comment (89 FR 2913). Unless otherwise noted, all weights in this final rule are in round weight.</P>
                <HD SOURCE="HD2">Red Snapper</HD>
                <P>Red snapper in the Gulf EEZ is harvested by both the commercial and recreational sectors. Each sector has its own ACL and associated management measures. The stock ACL is allocated 51 percent to the commercial sector and 49 percent to the recreational sector. The recreational ACL (quota) is further allocated between the Federal charter vessel/headboat (for-hire) component (42.3 percent) and the private angling component (57.7 percent).</P>
                <P>
                    In February 2020, NMFS implemented state management of red snapper for the private angling component through Amendments 50 A-F to the FMP (85 FR 6819, February 6, 2020). Through these amendments, each state was allocated a portion of the red snapper private angling component ACL and was delegated the authority to set the private angling fishing season, bag limit, and size limit. These amendments also established an accountability measure (AM) that required any overage of a state's ACL to be deducted in the following year (
                    <E T="03">i.e.,</E>
                     a payback provision).
                </P>
                <P>
                    In 2023, NMFS implemented a framework action under the FMP to calibrate the red snapper ACLs for Alabama, Florida, Louisiana, and Mississippi so they could be directly compared to the landings estimates produced by each of those state's data collection program (Calibration Framework) (87 FR 74014, December 2, 2022). As explained in the Calibration Framework final rule, each of these states have relatively new programs for monitoring red snapper landed by the private-angling component (beginning in 2014 for Alabama and Louisiana and 2015 for Florida and Mississippi), and these programs do not produce results that are comparable to each other or to Federal estimates generated by the Marine Recreational Information Program (MRIP). Prior to the development of these state programs, NMFS provided the only estimates of private angler red snapper landings, except for those in Texas (Texas anglers have never participated in the NMFS recreational data collection survey). The state-specific red snapper ACLs were established using the results of a stock assessment that included recreational landings estimates produced by MRIP. The Calibration Framework final rule applied state-specific ratios to these MRIP-based ACLs (Federal equivalent ACLs) to adjust each state's private-angling ACL to account for the monitoring programs used by each Gulf state and allow a direct comparison between the ACL and state landings 
                    <PRTPAGE P="41897"/>
                    estimate. The ratios implemented by the Calibration Framework final rule were: Alabama (0.4875), Florida (1.0602), Louisiana (1.06), Mississippi (0.3840), and Texas (1.00). The ratios for Alabama, Florida, Louisiana, and Mississippi were developed using available state landings data. More information on the data used to calculate the current ratios can be found in the Calibration Framework.
                </P>
                <P>In June 2022, the Council asked its Scientific and Statistical Committee (SSC) to review more recent state data and provide recommendations on any appropriate changes to the calibration ratios. Alabama, Florida, and Mississippi submitted updated data for review, and in January 2023, the SSC concluded that it was appropriate to modify the ratios for Alabama, Florida, and Mississippi to 0.548, 1.34, and 0.503, respectively.</P>
                <P>This final rule modifies the calibration ratios for Alabama, Florida, and Mississippi as recommended by the SSC and applies these ratios to the MRIP-based ACLs to update the state-survey-based ACLs. The framework action and this final rule will not change the MRIP-based (Federal equivalent) state ACLs or the total private-angling ACL. However, because the understanding of the relationship between the states' landings estimates and the Federal landings estimates have changed, NMFS expects each of the three states to increase the number of days that private anglers are allowed to harvest red snapper.</P>
                <HD SOURCE="HD2">Gray Snapper</HD>
                <P>Gray snapper in the Gulf EEZ is managed as a single stock with a stock ACL and a stock annual catch target (ACT), although the ACT is not codified in the regulations or used for management. There is no allocation of the stock ACL between the commercial and recreational sectors. AMs for gray snapper specify that if the combined commercial and recreational landings exceed the stock ACL in a fishing year, then during the following fishing year if the stock ACL is reached or is projected to be reached, the commercial and recreational sectors will be closed for the remainder of the fishing year. However, since the implementation of gray snapper catch limits in 2012, total landings have not exceeded the ACL.</P>
                <P>Prior to 2018, the status of the gray snapper stock had not been evaluated in a stock assessment. In 2018, a Southeast Data, Assessment, and Review (SEDAR) benchmark stock assessment for gray snapper was completed (SEDAR 51) and indicated that the stock was undergoing overfishing. SEDAR 51 included recreational landings estimates calibrated to the MRIP-Coastal Household Telephone Survey (CHTS). In response to this assessment, the Council developed and NMFS implemented Amendment 51 to the FMP, which established biological reference points, overfished status determination criteria, and the current catch limits for the gray snapper stock (85 FR 73238, November 17, 2020). These catch limits are an overfishing limit (OFL) of 2.57 million lb (1.17 million kg), acceptable biological catch (ABC) of 2.51 million lb (1.14 million kg), and stock ACL of 2.23 million lb (1.02 million kg).</P>
                <P>In December 2022, the Southeast Fisheries Science Center finalized a new stock assessment report for gray snapper (SEDAR 75). SEDAR 75 also incorporated updated recreational landings data calibrated to the MRIP-Fishing Effort Survey (FES). MRIP-FES replaced MRIP-CHTS in 2018, and total recreational fishing effort estimates generated from MRIP-FES are generally higher than MRIP-CHTS estimates.</P>
                <P>The Council's SSC reviewed the results of SEDAR 75 during its January 2023 meeting and determined that the assessment was consistent with the best scientific information available. Based on the results of SEDAR 75, the Council's SSC concluded the stock is not overfished or undergoing overfishing as of 2020 and also determined that the stock was not likely to have been experiencing overfishing in 2015, as was concluded in SEDAR 51.</P>
                <P>For this framework action, the Council recommended a constant catch OFL and ABC of 7.547 million lb (3.423 million kg) and 6.226 million lb (2.824 million kg), respectively. The Council also recommended an 8 percent buffer between the ABC and stock ACL, which is based on the Council's ACL/ACT control rule. This results in a revised stock ACL of 5.728 million lb (2.598 million kg). Because of the different recreational landings estimates used to determine the current and revised catch limits (MRIP-CHTS versus MRIP-FES), these catch limits are not directly comparable. Much of the increase in the new catch limits is due to the conversion from MRIP-CHTS to MRIP-FES. However, using recreational data collected in MRIP-CHTS for reference, the revised catch limits do represent an approximate increase of 15 percent from the current catch limits.</P>
                <HD SOURCE="HD1">Management Measures Contained in This Final Rule</HD>
                <HD SOURCE="HD2">Red Snapper</HD>
                <P>This final rule modifies the calibration ratios used by Alabama, Florida, and Mississippi to convert MRIP-based red snapper private angling component ACLs to state-survey-based red snapper private angling component ACLs and applies those ratios to update each state's ACL.</P>
                <P>As described above, the current state private recreational data calibration ratios for Alabama, Florida, and Mississippi are 0.4875, 1.0602, and 0.3840, respectively. The framework action and final rule revise the state private recreational calibration ratios for Alabama, Florida, and Mississippi to be 0.548, 1.34, and 0.503, respectively. NMFS notes that the calibration ratios are not codified in the regulations. Applying the new ratios to the MRIP-based, Federal equivalent ACLs (which remain the same) results in revised state-survey-based private angling component ACLs as follows: the Alabama private angling component ACL will be 664,552 lb (301,436 kg) with a Federal equivalent of 1,212,687 lb (550,066 kg); the Florida private angling component ACL will be 2,769,631 lb (1,256,283 kg) with a Federal equivalent of 2,066,889 lb (937,525 kg); and the Mississippi private angling component ACL will be 82,342 lb (37,350 kg) with a Federal equivalent of 163,702 lb (74,254 kg).</P>
                <HD SOURCE="HD2">Gray Snapper</HD>
                <P>As a result of SEDAR 75 and using data through 2020, this final rule revises the gray snapper stock ACL from 2.23 million lb (1.01 million kg) to 5.728 million lb (2.598 million kg). As explained previously, the current and revised ACLs are not directly comparable. However, total harvest has never exceeded the current ACL, and the revised stock ACL represents an increase in the allowable harvest.</P>
                <HD SOURCE="HD1">Comments and Responses</HD>
                <P>
                    NMFS received seven comment submissions in response to the proposed rule which were largely in support of the framework action and proposed rule. Several comments were outside the scope of the proposed rule, including that the gray snapper size limit is too low, Mississippi's red snapper allocation percentage is too low, recreational landings should be calculated in number of fish rather than in weight, NMFS and the Council must create a new recreational census-based reporting system that captures landings and discards, and NMFS and the 
                    <PRTPAGE P="41898"/>
                    Council must implement a mandatory recreational fishing permit for all Gulf anglers. While these comments discuss red and gray snapper management, this action is limited to modifying the gray snapper catch limits and modifying the red snapper calibration ratios for Alabama, Florida, and Mississippi and applying these ratios to the MRIP-based ACLs to update the state-survey-based ACLs. Broader issues such as size limits, state allocations, and monitoring methods are outside the scope of this action.
                </P>
                <P>Specific comments related to the proposed rule and the framework action are summarized below and followed by NMFS' respective responses.</P>
                <P>
                    <E T="03">Comment 1:</E>
                     NMFS should take a precautionary approach when drastic ACL changes are recommended based on MRIP-FES. For gray snapper, the drastic increase in the stock ACL (approximately 200 percent) is not precautionary, especially given the uncertainty of the MRIP-FES data and only 54 percent of last year's stock ACL was landed.
                </P>
                <P>
                    <E T="03">Response:</E>
                     Initially, NMFS notes that this final rule does not increase the gray snapper stock ACL by 200 percent. As explained previously, most of the increase in the new catch limits is due to the conversion from MRIP-CHTS to MRIP-FES. This conversion does not reflect greater harvest than previously allowed. It changes the scale of the catch limits to be consistent with the scale of survey used to monitor those catch limits. After accounting for the change to MRIP-FES, the increase in the gray snapper stock ACL is approximately 15 percent.
                </P>
                <P>NMFS does not agree that a precautionary approach is necessary with respect to the gray snapper catch limits given the current stock status of gray snapper. As required by the Magnuson-Stevens Act, the new catch limits are designed to prevent overfishing and achieve OY and are based on the best scientific information available, including recreational landings estimates calibrated to MRIP-FES, which indicates that gray snapper is not overfished or undergoing overfishing. Further, the new ACL takes into account both scientific and management uncertainty. The Council's SSC recommended an ABC that is approximately 13 percent lower than the recommended OFL, and this buffer between the OFL and the ABC accounts for scientific uncertainty and reduces the likelihood of overfishing. The Council accounted for management uncertainty and further reduced the likelihood of overfishing by recommending a stock ACL eight percent below the ABC.</P>
                <P>
                    <E T="03">Comment 2:</E>
                     States that exceed their red snapper private angling component ACLs should not be rewarded with calibration ratios that increase their allowable harvest. Alabama, Mississippi, and Texas benefitted from a de facto reallocation of the recreational ACL by exceeding their red snapper private angling component ACLs between 2018 and 2021 without repercussion. These states should not be rewarded with increased allocation percentages based their ACL overages.
                </P>
                <P>
                    <E T="03">Response:</E>
                     It is unclear how the commenter determined that Alabama, Mississippi, and Texas exceeded their respective ACLs or benefitted from any de facto reallocation. In 2018 and 2019, all of the Gulf states were operating under exempted fishing permits that allowed each state to set the red snapper fishing season for private anglers landing red snapper in that state. The state-specific catch levels in each EFP were based on the amounts requested by each state, which equaled 96.22 percent of the total private angling component ACL. The EFPs required each state to pay back any overage of its ACL. Florida and Alabama exceeded their ACLs in 2018 and Louisiana exceeded its ACL in 2019; those overages were paid back in the following years. More information about the EFPs and the state landings in 2018 and 2019 can be found at 
                    <E T="03">https://www.fisheries.noaa.gov/southeast/state-recreational-red-snapper-management-exempted-fishing-permits#permits.</E>
                </P>
                <P>Since 2020, each state has been operating under the authority delegated in the final rule implementing Amendments 50A-F, which specified the state-specific allocations and ACLs. However, at the time Amendments 50A-F were implemented the state-specific ACLs had not been calibrated to each state's survey. In the final rule implementing the state calibration ratios, NMFS acknowledged that the lack of the calibrated state ACLs had allowed the combined landings from the Gulf States to exceed the total private angling component ACL. NMFS also explained that when state reported landings exceeded the codified state ACLs, NMFS implemented paybacks to address the state ACL overages, but no paybacks for Mississippi or Alabama had been implemented because landings estimates provided by these states did not exceed their ACLs as codified in 2020, 2021, and 2022 (see 87 FR at 74014). The calibrated state ACLs now allow NMFS to directly compare each state's landings estimate to its ACL and implement any necessary payback.</P>
                <P>The Council did not consider and NMFS is not making changes to the state allocations. This final rule is adjusting how Alabama, Florida, and Mississippi's red snapper private angling program landings estimates compare to the MRIP-based landings estimates. Thus while this final rule increases the state-survey based red snapper ACLs, the MRIP-based survey (Federal equivalent) ACLs remain the same. The allocation percentages adopted in Amendment 50A are based on the MRIP-based ACL, and this final rule is not changing each Gulf state's percentage of that MRIP-based ACL.</P>
                <P>
                    <E T="03">Comment 3:</E>
                     NMFS must require all five Gulf states to publicly report landings in a standardized and timely manner, and NMFS must provide a central location that publicizes recreational red snapper landings and discard information from the states both in “state currency” landings and the appropriate “common currency” landings once those data are finalized.
                </P>
                <P>
                    <E T="03">Response:</E>
                     NMFS disagrees that it is appropriate to require the states to report in a standardized manner because Amendments 50A-F were designed to allow each state to manage red snapper harvest by the private-angling component using their own systems, which are not uniform. NMFS publishes red snapper recreational landings from each Gulf state, as estimated by each state survey (state currency) and as estimated by MRIP (common currency) when NMFS receives the data from all of the Gulf states for a fishing year. NMFS does not have control over when the data from each Gulf state are submitted, so landings data may not be publicly available for a number of months after the end of a fishing year. In addition, the Gulf states' estimates may be updated by a state after they are submitted to NMFS, and those changes may occur months or years after the data have been initially submitted. For this reason, NMFS publishes the red snapper recreational landings data as most recently reported by the states without change. NMFS does not require that the states provide estimates of red snapper recreational discards because the state ACLs are expressed in terms of landed fish only. Therefore, NMFS does not publish state discard data. The most recent private recreational landings data, estimated by MRIP and as submitted by the Gulf states, can be found at: 
                    <E T="03">https://www.fisheries.noaa.gov/southeast/recreational-fishing-data/gulf-mexico-historical-recreational-landings-and-annual-catch.</E>
                    <PRTPAGE P="41899"/>
                </P>
                <HD SOURCE="HD1">Classification</HD>
                <P>Pursuant to section 304(b)(3) of the Magnuson-Stevens Act, the NMFS Assistant Administrator has determined that this final rule is consistent with the framework action, the FMP, other provisions of the Magnuson-Stevens Act, the U.S. Constitution, and other applicable law.</P>
                <P>This final rule has been determined to be not significant for purposes of Executive Order 12866.</P>
                <P>The Magnuson-Stevens Act provides the legal basis for this final rule. No duplicative, overlapping, or conflicting Federal rules have been identified.</P>
                <P>
                    A description of this final rule, why it is being considered, and the purpose of this final rule are contained in the 
                    <E T="02">SUMMARY</E>
                     and 
                    <E T="02">SUPPLEMENTARY INFORMATION</E>
                     sections of this final rule. The objective of this final rule is to improve the management of red snapper and gray snapper based on the best scientific information available.
                </P>
                <P>The Chief Counsel for Regulation of the Department of Commerce certified to the Chief Counsel for Advocacy of the Small Business Administration (SBA) during the proposed rule stage that this action would not have a significant economic impact on a substantial number of small entities. The factual basis for the certification was published in the proposed rule and is not repeated here. NMFS did not receive any comments from SBA's Office of Advocacy or the public regarding the certification in the proposed rule. As a result, a final regulatory flexibility analysis was not required and none was prepared.</P>
                <P>This final rule contains no information collection requirements under the Paperwork Reduction Act of 1995.</P>
                <LSTSUB>
                    <HD SOURCE="HED">List of Subjects in 50 CFR Part 622</HD>
                    <P>Annual catch limits, Fisheries, Fishing, Gulf, Recreational, Red snapper, Reef fish.</P>
                </LSTSUB>
                <SIG>
                    <DATED>Dated: May 8, 2024.</DATED>
                    <NAME>Samuel D. Rauch, III,</NAME>
                    <TITLE>Deputy Assistant Administrator for Regulatory Programs, National Marine Fisheries Service.</TITLE>
                </SIG>
                <P>For the reasons set out in the preamble, NMFS amends 50 CFR part 622 as follows:</P>
                <PART>
                    <HD SOURCE="HED">PART 622—FISHERIES OF THE CARIBBEAN, GULF OF MEXICO, AND SOUTH ATLANTIC</HD>
                </PART>
                <REGTEXT TITLE="50" PART="622">
                    <AMDPAR>1. The authority citation for part 622 continues to read as follows:</AMDPAR>
                    <AUTH>
                        <HD SOURCE="HED">Authority:</HD>
                        <P>
                             16 U.S.C. 1801 
                            <E T="03">et seq.</E>
                              
                        </P>
                    </AUTH>
                </REGTEXT>
                <REGTEXT TITLE="50" PART="622">
                    <AMDPAR>2. In § 622.23, revise paragraphs (a)(1)(ii)(A), (B), and (D) to read as follows:</AMDPAR>
                    <SECTION>
                        <SECTNO>§ 622.23</SECTNO>
                        <SUBJECT>State management of the red snapper recreational sector private angling component in the Gulf EEZ.</SUBJECT>
                        <P>(a) * * *</P>
                        <P>(1) * * *</P>
                        <P>(ii) * * *</P>
                        <P>
                            (A) 
                            <E T="03">Alabama regional management area</E>
                            —664,552 lb (301,436 kg); Federal equivalent—1,212,687 lb (550,066 kg).
                        </P>
                        <P>
                            (B) 
                            <E T="03">Florida regional management area</E>
                            —2,769,631 lb (1,256,283 kg); Federal equivalent—2,066,889 lb (937,525 kg).
                        </P>
                        <STARS/>
                        <P>
                            (D) 
                            <E T="03">Mississippi regional management area</E>
                            —82,342 lb (37,350 kg); Federal equivalent—163,702 lb (74,254 kg).
                        </P>
                        <STARS/>
                    </SECTION>
                </REGTEXT>
                <REGTEXT TITLE="50" PART="622">
                    <AMDPAR>3. In § 622.41, revise paragraph (l) to read as follows:</AMDPAR>
                    <SECTION>
                        <SECTNO>§ 622.41</SECTNO>
                        <SUBJECT>Annual catch limits (ACLs), annual catch targets (ACTs), and accountability measures (AMs).</SUBJECT>
                        <STARS/>
                        <P>
                            (l) 
                            <E T="03">Gray snapper.</E>
                             If the sum of the commercial and recreational landings, as estimated by the SRD, exceeds the stock ACL, then during the following fishing year, if the sum of commercial and recreational landings reaches or is projected to reach the stock ACL, the AA will file a notification with the Office of the Federal Register to close the commercial and recreational sectors for the remainder of that fishing year. The stock ACL for gray snapper is 5.728 million lb (2.598 million kg), round weight.
                        </P>
                        <STARS/>
                    </SECTION>
                </REGTEXT>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10468 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3510-22-P</BILCOD>
        </RULE>
        <RULE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF COMMERCE</AGENCY>
                <SUBAGY>National Oceanic and Atmospheric Administration</SUBAGY>
                <CFR>50 CFR Part 648</CFR>
                <DEPDOC>[Docket No. 231215-0305; RTID 0648-XD957]</DEPDOC>
                <SUBJECT>Fisheries of the Northeastern United States; Summer Flounder Fishery; Quota Transfer From North Carolina to Virginia</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Temporary rule; quota transfer.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>NMFS announces that the State of North Carolina is transferring a portion of its 2024 commercial summer flounder quota to the Commonwealth of Virginia. This adjustment to the 2024 fishing year quota is necessary to comply with the Summer Flounder, Scup, and Black Sea Bass Fishery Management Plan (FMP) quota transfer provisions. This announcement informs the public of the revised 2024 commercial quotas for North Carolina and Virginia.</P>
                </SUM>
                <EFFDATE>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Effective May 13, 2024 through December 31, 2024.</P>
                </EFFDATE>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Laura Deighan, Fishery Management Specialist, (978) 281-9184.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>Regulations governing the summer flounder fishery are found in 50 CFR 648.100 through 648.111. These regulations require annual specification of a commercial quota that is apportioned among the coastal states from Maine through North Carolina. The process to set the annual commercial quota and the percent allocated to each state is described in § 648.102, and the final 2024 allocations were published on December 21, 2023 (88 FR 88266).</P>
                <P>
                    The final rule implementing amendment 5 to the Summer Flounder FMP, as published in the 
                    <E T="04">Federal Register</E>
                     on December 17, 1993 (58 FR 65936), provided a mechanism for transferring summer flounder commercial quota from one state to another. Two or more states, under mutual agreement and with the concurrence of the NMFS Greater Atlantic Regional Administrator, can transfer or combine summer flounder commercial quota under § 648.102(c)(2). The Regional Administrator is required to consider three criteria in the evaluation of requests for quota transfers or combinations: (1) the transfers or combinations would not preclude the overall annual quota from being fully harvested; (2) the transfers address an unforeseen variation or contingency in the fishery; and (3) the transfers are consistent with the objectives of the FMP and the Magnuson-Stevens Fishery Conservation and Management Act (Magnuson-Stevens Act). The Regional Administrator has determined these three criteria have been met for the transfer approved in this notification.
                </P>
                <P>
                    North Carolina is transferring 18,043 pounds (lb; 8,184 kilograms (kg)) to Virginia through a mutual agreement between the states. This transfer was requested to repay landings made by an out-of-state permitted vessel under a safe harbor agreement. The revised summer flounder quotas for 2024 are: North Carolina, 2,391,124 lb (1,084,596 
                    <PRTPAGE P="41900"/>
                    kg); and Virginia, 1,883,980 lb (854,559 kg).
                </P>
                <HD SOURCE="HD1">Classification</HD>
                <P>NMFS issues this action pursuant to section 305(d) of the Magnuson-Stevens Act. This action is required by 50 CFR 648.102(c)(2)(i) through (iv), which was issued pursuant to section 304(b), and is exempted from review under Executive Order 12866.</P>
                <AUTH>
                    <HD SOURCE="HED">Authority:</HD>
                    <P>
                        16 U.S.C. 1801 
                        <E T="03">et seq.</E>
                    </P>
                </AUTH>
                <SIG>
                    <DATED>Dated: May 9, 2024.</DATED>
                    <NAME>Karen H. Abrams,</NAME>
                    <TITLE>Acting Director, Office of Sustainable Fisheries, National Marine Fisheries Service.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10573 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3510-22-P</BILCOD>
        </RULE>
    </RULES>
    <VOL>89</VOL>
    <NO>94</NO>
    <DATE>Tuesday, May 14, 2024</DATE>
    <UNITNAME>Proposed Rules</UNITNAME>
    <PRORULES>
        <PRORULE>
            <PREAMB>
                <PRTPAGE P="41901"/>
                <AGENCY TYPE="F">NUCLEAR REGULATORY COMMISSION</AGENCY>
                <CFR>10 CFR Part 72 and 73</CFR>
                <DEPDOC>[Docket No. PRM-72-6; NRC-2009-0558; NRC-2008-0649]</DEPDOC>
                <RIN>RIN 3150-AI78</RIN>
                <SUBJECT>Independent Spent Fuel Storage Installation Security Requirements</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Nuclear Regulatory Commission.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Discontinuation of rulemaking activity; denial of petition for rulemaking.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The U.S. Nuclear Regulatory Commission (NRC) is discontinuing the rulemaking activity, “Independent Spent Fuel Storage Installation Security Requirements for Radiological Sabotage,” and denying Request 11 in the associated petition for rulemaking (PRM), PRM-72-6. The purpose of this action is to inform members of the public that this rulemaking activity is being discontinued and to provide a brief discussion of the NRC's decision to discontinue the rulemaking and deny the petition. The rulemaking activity will no longer be reported in the NRC's portion of the Unified Agenda of Regulatory and Deregulatory Actions (the Unified Agenda).</P>
                </SUM>
                <EFFDATE>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>As of May 14, 2024, the rulemaking activity discussed in this document is discontinued and Request 11 in the petition for rulemaking is denied.</P>
                </EFFDATE>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>Please refer to Docket IDs NRC-2009-0558 or NRC-2008-0649 when contacting the NRC about the availability of information for this action. You may obtain publicly available information related to this action by any of the following methods:</P>
                    <P>
                        • 
                        <E T="03">Federal Rulemaking Website:</E>
                         Go to 
                        <E T="03">https://www.regulations.gov</E>
                         and search for Docket ID NRC-2009-0558 or NRC-2008-0649. Address questions about NRC dockets to Angella Love Blair; email: 
                        <E T="03">angella.loveblair@nrc.gov.</E>
                         For technical questions, contact the individuals listed in the 
                        <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                         section of this document.
                    </P>
                    <P>
                        • 
                        <E T="03">NRC's Agencywide Documents Access and Management System (ADAMS):</E>
                         You may obtain publicly available documents online in the ADAMS Public Documents collection at 
                        <E T="03">https://www.nrc.gov/reading-rm/adams.html.</E>
                         To begin the search, select “Begin Web-based ADAMS Search.” For problems with ADAMS, please contact the NRC's Public Document Room (PDR) reference staff at 1-800-397-4209, at 301-415-4737, or by email to 
                        <E T="03">pdr.resource@nrc.gov.</E>
                         For the convenience of the reader, instructions about obtaining materials referenced in this document are provided in the “Availability of Documents” section.
                    </P>
                    <P>
                        • 
                        <E T="03">NRC's PDR:</E>
                         The PDR, where you may examine and order copies of publicly available documents, is open by appointment. To make an appointment to visit the PDR, please send an email to 
                        <E T="03">pdr.resource@nrc.gov</E>
                         or call 1-800-397-4209 or 301-415-4737, between 8 a.m. and 4 p.m. eastern time, Monday through Friday, except Federal holidays.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Gregory Trussell, Office of Nuclear Material Safety and Safeguards; telephone: 301-415-6244; email: 
                        <E T="03">Gregory.Trussell@nrc.gov;</E>
                         or Johari Moore, Office of Nuclear Security and Incident Response; telephone: 301-287-3787; email: 
                        <E T="03">Johari.Moore@nrc.gov.</E>
                         Both are staff of the U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P/>
                <HD SOURCE="HD1">I. Background</HD>
                <HD SOURCE="HD2">A. Independent Spent Fuel Storage Installation (ISFSI) Security Requirements Rulemaking</HD>
                <P>In SECY-07-0148, “Independent Spent Fuel Storage Installation Requirements for Radiological Sabotage,” dated August 28, 2007, the NRC staff proposed to develop new security requirements to update the security regulations for ISFSIs. Following subsequent analysis, as directed by the Commission in staff requirements memorandum (SRM) SRM-COMKLS-18-003, “Fiscal Year 2020 Budget to the Commission,” dated August 22, 2018, and SRM-SECY-19-0100, “Discontinuation of Rulemaking-Independent Spent Fuel Storage Installation Security Requirements,” dated August 4, 2021, the staff provided SECY-22-0098, “Rulemaking Options for Revising Security Requirements for Facilities Storing Spent Nuclear Fuel and High-Level Radioactive Waste.”</P>
                <P>In SECY-22-0098, the staff outlined its determination that the current regulatory framework, including the additional requirements in the post-9/11 security orders, provides reasonable assurance of adequate protection of public health and safety for facilities storing spent nuclear fuel and high-level radioactive waste and recommended that the Commission approve discontinuing the rulemaking directed by the Commission in SRM-SECY-07-0148, “Staff Requirements—SECY-07-0148—Independent Spent Fuel Storage Installation Security Requirements for Radiological Sabotage.” In SRM-SECY-22-0098, dated October 4, 2023, the Commission approved discontinuing the rulemaking.</P>
                <HD SOURCE="HD2">B. Petition for Rulemaking</HD>
                <P>
                    Section 2.802 of title 10 of the 
                    <E T="03">Code of Federal Regulations</E>
                     (10 CFR), “Petition for rulemaking,” provides an opportunity for any interested person to petition the Commission to issue, amend, or rescind any regulation. On November 24, 2008, the NRC received a PRM filed by Sandra Gavutis (the petitioner), Executive Director of C-10 Research and Education Foundation, Inc. The petitioner requested that the NRC amend its regulations concerning dry cask safety, security, transferability, and longevity. The petitioner made 12 specific requests in the petition. The NRC docketed the petition as PRM-72-6 and documented it in the 
                    <E T="04">Federal Register</E>
                     for public comment on March 3, 2009 (74 FR 9178). The staff discussed its review of the petition and the comments received in SECY-12-0079, “Partial Closure of Petition for Rulemaking (PRM-72-6) C-10 Research and Education Foundation, Inc.,” dated June 1, 2012. The Commission approved the staff's recommendation for partial closure of the PRM in SRM-SECY-12-0079, dated September 7, 2012. In a 
                    <E T="04">Federal Register</E>
                     document dated October 16, 2012 (77 FR 63254), the NRC denied 9 of the petitioner's 12 specific requests (Requests 1-3, 5-8, 10, and 12), reserved 2 requests for future 
                    <PRTPAGE P="41902"/>
                    rulemaking determination (Requests 4 and 9), and accepted 1 request (Request 11) for consideration as part of the ISFSI security requirements rulemaking effort. Subsequently, the NRC announced its final decision to deny Requests 4 and 9 in the 
                    <E T="04">Federal Register</E>
                     on June 24, 2016 (81 FR 41258). As stated in the petition, Request 11 in PRM-72-6 requested that the NRC amend its regulations to do the following:
                </P>
                <EXTRACT>
                    <P>[R]equire Hardened On-Site Storage (HOSS) at all nuclear power plants as well as away-from-reactor dry cask storage sites: that all nuclear industry interim on-site or off-site dry cask storage installations or ISFSIs be fortified against attack. In addition all sites should be safeguarded against accident and age-related leakage.</P>
                </EXTRACT>
                <P>In SECY-19-0100, the staff recommended that the Commission deny Request 11 in PRM-72-6. Following the receipt of SRM-SECY-22-0098, the NRC staff submitted SECY-24-0006, “Denial of Request 11 in PRM-72-6 as Part of Notice Discontinuing Independent Spent Fuel Storage Installation Security Requirements Rulemaking,” dated January 22, 2024. In SRM-SECY-24-0006, dated January 31, 2024, the Commission approved the staff's recommendation.</P>
                <HD SOURCE="HD1">II. Discussion</HD>
                <HD SOURCE="HD2">A. Discontinuation of Rulemaking Activity</HD>
                <P>In SRM-SECY-22-0098, dated October 4, 2023, the Commission approved discontinuing the rulemaking. The NRC finds that the current regulatory framework provides reasonable assurance of adequate protection of public health and safety for facilities storing spent nuclear fuel and high-level radioactive waste, regardless of the ISFSI license type or location. The NRC's experience shows that the staff, licensees, applicants, and other stakeholders have been able to understand and apply the existing ISFSI security requirements, and the NRC has successfully addressed the appropriate security considerations for new license applicants on a case-by-case basis.</P>
                <HD SOURCE="HD2">B. Denial of Petition for Rulemaking</HD>
                <P>
                    Following the receipt of SRM-SECY-22-0098, the NRC staff submitted SECY-24-0006, “Denial of Request 11 In PRM-72-6 as Part of Notice Discontinuing Independent Spent Fuel Storage Installation Security Requirements Rulemaking,” dated January 22, 2024. The staff recommended that the Commission deny Request 11 in PRM-72-6. The staff also noted that, in the 2012 
                    <E T="04">Federal Register</E>
                     document that accepted Request 11 for consideration within the context of the ISFSI security rulemaking effort (77 FR 63254, 63256), the NRC stated that it has not mandated hardened on-site storage because the NRC “has, consistently, found that the robust nature of dry cask storage systems approved by the NRC under 10 CFR part 72 assures the protection of public health, safety, and security.” This statement was made in 2012 in response to public comments on Request 11. In SRM-SECY-24-0006, dated January 31, 2024, the Commission approved the staff's recommendation. The NRC is denying Request 11 in PRM-72-6 because the NRC has found that the existing security requirements for ISFSIs, together with the additional requirements in the post-9/11 security orders, provide reasonable assurance of adequate protection of public health and safety.
                </P>
                <HD SOURCE="HD1">III. Availability of Documents</HD>
                <P>The documents identified in the following table are available to interested persons through one or more of the following methods, as indicated.</P>
                <GPOTABLE COLS="2" OPTS="L2,nj,tp0,i1" CDEF="s200,xs115">
                    <TTITLE> </TTITLE>
                    <BOXHD>
                        <CHED H="1">Document</CHED>
                        <CHED H="1">
                            ADAMS accession No. or
                            <LI>
                                <E T="02">Federal Register</E>
                                 citation
                            </LI>
                        </CHED>
                    </BOXHD>
                    <ROW>
                        <ENT I="01">Petition for Rulemaking, “The C-I0 Research and Education Foundation Inc. Petition for NRC Rulemaking to Upgrade Interim Dry Cask Storage Code Requirements” (November 24, 2008)</ENT>
                        <ENT>ML083470148.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">10 CFR Part 72, “C-10 Research and Education Foundation, Inc.; Receipt of Petition for Rulemaking” (March 3, 2009)</ENT>
                        <ENT>74 FR 9178.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">SECY-12-0079, “Partial Closure of Petition for Rulemaking (PRM-72-6) C-10 Research and Education Foundation, Inc.” (September 7, 2012)</ENT>
                        <ENT>ML12251A238.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">10 CFR Part 72, “Petition for Rulemaking Submitted by C-10 Research and Education Foundation, Inc.: Petition for rulemaking; partial consideration in the rulemaking process” (October 16, 2012)</ENT>
                        <ENT>77 FR 63254.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">10 CFR Part 72, “Petition for Rulemaking Submitted by C-10 Research and Education Foundation, Inc.: Petition for rulemaking; denial” (June 24, 2016)</ENT>
                        <ENT>81 FR 41258.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">SRM-SECY-07-0148, “Staff Requirements—SECY-07-0148—Independent Spent Fuel Storage Installation Security Requirements for Radiological Sabotage” (December 18, 2017)</ENT>
                        <ENT>ML073530119.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">SRM-COMKLS-18-003, “Fiscal Year 2020 Budget to the Commission” (August 22, 2018)</ENT>
                        <ENT>ML18234A238 (nonpublic, budget information).</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">SECY-19-0100, “Discontinuation of Rulemaking-Independent Spent Fuel Storage Installation Security Requirements” (October 9, 2019)</ENT>
                        <ENT>ML19172A301 (package).</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">SRM-SECY-19-0100, “Staff Requirements—SECY-19-0100—Discontinuation of Rulemaking Independent Spent Fuel Storage Installation Security Requirements” (August 4, 2021)</ENT>
                        <ENT>ML21217A045.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">SECY-22-0098, “Rulemaking Options for Revising Security Requirements for Facilities Storing Spent Nuclear Fuel and High-Level Radioactive Waste” (November 30, 2022)</ENT>
                        <ENT>ML22243A143 (package).</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">SRM-SECY-22-0098, “Staff Requirements—SECY-22-0098—Rulemaking Options for Revising Security Requirements for Facilities Storing Spent Nuclear Fuel and High-Level Radioactive Waste” (October 4, 2023)</ENT>
                        <ENT>ML23277A281.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">SECY-07-0148, “Independent Spent Fuel Storage Installation Requirements for Radiological Sabotage” (August 28, 2007)</ENT>
                        <ENT>ML080250294.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">SRM-SECY-24-0006, “Denial of Request 11 in Petition for Rulemaking (PRM)-72-6 as Part of Notice Discontinuing Independent Spent Fuel Storage Installation Security Requirements Rulemaking” (January 31, 2024)</ENT>
                        <ENT>ML24031A573.</ENT>
                    </ROW>
                </GPOTABLE>
                <HD SOURCE="HD1">IV. Conclusion</HD>
                <P>
                    The NRC is discontinuing the ISFSI security requirements rulemaking and is denying Request 11 in PRM-72-6 for the reasons discussed in this document. In the next edition of the Unified Agenda, the NRC will update the entry for this rulemaking activity and reference this document to indicate that the rulemaking activity is no longer being pursued. This rulemaking activity will appear in the Completed Actions section of that edition of the Unified Agenda but will not appear in future editions. If the NRC decides to pursue 
                    <PRTPAGE P="41903"/>
                    similar or related rulemaking activities in the future, it will inform the public through new rulemaking entries in the Unified Agenda.
                </P>
                <SIG>
                    <DATED>Dated: May 2, 2024.</DATED>
                    <P>For the Nuclear Regulatory Commission.</P>
                    <NAME>Raymond Furstenau,</NAME>
                    <TITLE>Acting Executive Director for Operations.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10480 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 7590-01-P</BILCOD>
        </PRORULE>
        <PRORULE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF TRANSPORTATION</AGENCY>
                <SUBAGY>Federal Aviation Administration</SUBAGY>
                <CFR>14 CFR Part 39</CFR>
                <DEPDOC>[Docket No. FAA-2024-1293; Project Identifier MCAI-2023-01283-T]</DEPDOC>
                <RIN>RIN 2120-AA64</RIN>
                <SUBJECT>Airworthiness Directives; Saab AB, (Formerly Known as Saab AB, Support and Services) Airplanes</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Aviation Administration (FAA), DOT.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of proposed rulemaking (NPRM).</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The FAA proposes to supersede Airworthiness Directive (AD) 2021-26-05, which applies to all Saab AB Model SAAB 2000 airplanes. AD 2021-26-05 requires revising the existing maintenance or inspection program, as applicable, to incorporate new or more restrictive airworthiness limitations. Since the FAA issued AD 2021-26-05, the FAA has determined that new or more restrictive airworthiness limitations are necessary. This proposed AD would continue to require certain actions in AD 2021-26-05 and require revising the existing maintenance or inspection program, as applicable, to incorporate new or more restrictive airworthiness limitations, as specified in a European Union Aviation Safety Agency (EASA) AD, which is proposed for incorporation by reference (IBR). The FAA is proposing this AD to address the unsafe condition on these products.</P>
                </SUM>
                <EFFDATE>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The FAA must receive comments on this NPRM by June 28, 2024.</P>
                </EFFDATE>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>You may send comments, using the procedures found in 14 CFR 11.43 and 11.45, by any of the following methods:</P>
                    <P>
                        • 
                        <E T="03">Federal eRulemaking Portal:</E>
                         Go to 
                        <E T="03">regulations.gov</E>
                        . Follow the instructions for submitting comments.
                    </P>
                    <P>
                        • 
                        <E T="03">Fax:</E>
                         202-493-2251.
                    </P>
                    <P>
                        • 
                        <E T="03">Mail:</E>
                         U.S. Department of Transportation, Docket Operations, M-30, West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE, Washington, DC 20590.
                    </P>
                    <P>
                        • 
                        <E T="03">Hand Delivery:</E>
                         Deliver to Mail address above between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays.
                    </P>
                    <P>
                        <E T="03">AD Docket:</E>
                         You may examine the AD docket at 
                        <E T="03">regulations.gov</E>
                         under Docket No. FAA-2024-1293; or in person at Docket Operations between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. The AD docket contains this NPRM, the mandatory continuing airworthiness information (MCAI), any comments received, and other information. The street address for Docket Operations is listed above.
                    </P>
                    <P>
                        <E T="03">Material Incorporated by Reference:</E>
                    </P>
                    <P>
                        • For EASA material, contact EASA, Konrad-Adenauer-Ufer 3, 50668 Cologne, Germany; telephone +49 221 8999 000; email 
                        <E T="03">ADs@easa.europa.eu</E>
                        ; website 
                        <E T="03">easa.europa.eu</E>
                        . You may find this EASA AD on the EASA website at 
                        <E T="03">ad.easa.europa.eu</E>
                        .
                    </P>
                    <P>
                        • You may view this service information at the FAA, Airworthiness Products Section, Operational Safety Branch, 2200 South 216th St., Des Moines, WA. For information on the availability of this material at the FAA, call 206-231-3195. It is also available at 
                        <E T="03">regulations.gov</E>
                         under Docket No. FAA-2024-1293.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Shahram Daneshmandi, Aviation Safety Engineer, FAA, 1600 Stewart Avenue Suite 410, Westbury, NY 11590; phone: 206-231-3220; email: 
                        <E T="03">shahram.daneshmandi@faa.gov</E>
                        .
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P/>
                <HD SOURCE="HD1">Comments Invited</HD>
                <P>
                    The FAA invites you to send any written relevant data, views, or arguments about this proposal. Send your comments to an address listed under 
                    <E T="02">ADDRESSES</E>
                    . Include “Docket No. FAA-2024-1293; Project Identifier MCAI-2023-01283-T” at the beginning of your comments. The most helpful comments reference a specific portion of the proposal, explain the reason for any recommended change, and include supporting data. The FAA will consider all comments received by the closing date and may amend the proposal because of those comments.
                </P>
                <P>
                    Except for Confidential Business Information (CBI) as described in the following paragraph, and other information as described in 14 CFR 11.35, the FAA will post all comments received, without change, to 
                    <E T="03">regulations.gov</E>
                    , including any personal information you provide. The agency will also post a report summarizing each substantive verbal contact received about this NPRM.
                </P>
                <HD SOURCE="HD1">Confidential Business Information</HD>
                <P>
                    CBI is commercial or financial information that is both customarily and actually treated as private by its owner. Under the Freedom of Information Act (FOIA) (5 U.S.C. 552), CBI is exempt from public disclosure. If your comments responsive to this NPRM contain commercial or financial information that is customarily treated as private, that you actually treat as private, and that is relevant or responsive to this NPRM, it is important that you clearly designate the submitted comments as CBI. Please mark each page of your submission containing CBI as “PROPIN.” The FAA will treat such marked submissions as confidential under the FOIA, and they will not be placed in the public docket of this NPRM. Submissions containing CBI should be sent to Shahram Daneshmandi, Aviation Safety Engineer, FAA, 1600 Stewart Avenue, Suite 410, Westbury, NY 11590; phone: 206-231-3220; email: 
                    <E T="03">shahram.daneshmandi@faa.gov</E>
                    . Any commentary that the FAA receives that is not specifically designated as CBI will be placed in the public docket for this rulemaking.
                </P>
                <HD SOURCE="HD1">Background</HD>
                <P>The FAA issued AD 2021-26-05, Amendment 39-21863 (87 FR 1335, January 11, 2022) (AD 2021-26-05), for all Saab AB, Support and Services Model SAAB 2000 airplanes. AD 2021-26-05 was prompted by an MCAI originated by the European Union Aviation Safety Agency (EASA), which is the Technical Agent for the Member States of the European Union. EASA issued AD 2021-0132, dated May 25, 2021 (EASA AD 2021-0132) (which corresponds to FAA AD 2021-26-05), to correct an unsafe condition.</P>
                <P>AD 2021-26-05 requires revising the existing maintenance or inspection program, as applicable, to incorporate new or more restrictive airworthiness limitations. The FAA issued AD 2021-26-05 to address, among other things, fatigue cracking of principal structural elements (PSEs) and corrosion prevention and control. This unsafe condition, if not addressed, could result in reduced structural integrity of a PSE, and lead to loss of control of the airplane.</P>
                <HD SOURCE="HD1">Actions Since AD 2021-26-05 Was Issued</HD>
                <P>
                    Since the FAA issued AD 2021-26-05, EASA superseded AD 2021-0132, and issued EASA AD 2023-0220, dated December 21, 2023 (EASA AD 2023-0220) (referred to after this as the MCAI) for all Saab AB Model SAAB 2000 
                    <PRTPAGE P="41904"/>
                    airplanes. The MCAI states new or more restrictive airworthiness limitations have been developed.
                </P>
                <P>The FAA is proposing this AD to address among other things, fatigue cracking of PSEs and corrosion prevention and control. This unsafe condition, if not addressed, could result in reduced structural integrity of a PSE, and lead to loss of control of the airplane.</P>
                <P>
                    You may examine the MCAI in the AD docket at 
                    <E T="03">regulations.gov</E>
                     under Docket No. FAA-2024-1293.
                </P>
                <HD SOURCE="HD1">Related Service Information Under 1 CFR Part 51</HD>
                <P>The FAA reviewed EASA AD 2023-0220. This service information specifies new or more restrictive airworthiness limitations for airplane structures and safe life limits.</P>
                <P>This proposed AD would also require EASA AD 2021-0132, which the Director of the Federal Register approved for incorporation by reference as of February 15, 2022 (87 FR 1335, January 11, 2022).</P>
                <P>
                    This service information is reasonably available because the interested parties have access to it through their normal course of business or by the means identified in the 
                    <E T="02">ADDRESSES</E>
                     section.
                </P>
                <HD SOURCE="HD1">FAA's Determination</HD>
                <P>This product has been approved by the aviation authority of another country and is approved for operation in the United States. Pursuant to the FAA's bilateral agreement with this State of Design Authority, it has notified the FAA of the unsafe condition described in the MCAI referenced above. The FAA is issuing this NPRM after determining that the unsafe condition described previously is likely to exist or develop on other products of the same type design.</P>
                <HD SOURCE="HD1">Proposed Requirements of This NPRM</HD>
                <P>This proposed AD would retain certain requirements of AD 2021-26-05. This proposed AD would also require revising the existing maintenance or inspection program, as applicable, to incorporate new or more restrictive airworthiness limitations, which are specified in EASA AD 2023-0220 described previously, as incorporated by reference. Any differences with EASA AD 2023-0220 are identified as exceptions in the regulatory text of this AD.</P>
                <P>
                    This proposed AD would require revisions to certain operator maintenance documents to include new actions (
                    <E T="03">e.g.,</E>
                     inspections) and Critical Design Configuration Control Limitations (CDCCLs). Compliance with these actions and CDCCLs is required by 14 CFR 91.403(c). For airplanes that have been previously modified, altered, or repaired in the areas addressed by this proposed AD, the operator may not be able to accomplish the actions described in the revisions. In this situation, to comply with 14 CFR 91.403(c), the operator must request approval for an alternative method of compliance (AMOC) according to paragraph (m)(1) of this proposed AD.
                </P>
                <HD SOURCE="HD1">Explanation of Required Compliance Information</HD>
                <P>
                    In the FAA's ongoing efforts to improve the efficiency of the AD process, the FAA developed a process to use some civil aviation authority (CAA) ADs as the primary source of information for compliance with requirements for corresponding FAA ADs. The FAA has been coordinating this process with manufacturers and CAAs. As a result, the FAA proposes to retain the IBR of EASA AD 2021-0132 and incorporate EASA AD 2023-0220 by reference in the FAA final rule. This proposed AD would, therefore, require compliance with EASA AD 2021-0132 and EASA AD 2023-0220 through that incorporation, except for any differences identified as exceptions in the regulatory text of this proposed AD. Using common terms that are the same as the heading of a particular section in EASA AD 2021-0132 or EASA AD 2023-0220 does not mean that operators need comply only with that section. For example, where the AD requirement refers to “all required actions and compliance times,” compliance with this AD requirement is not limited to the section titled “Required Action(s) and Compliance Time(s)” in EASA AD 2021-0132 or EASA AD 2023-0220. Service information required by EASA AD 2021-0132 and EASA AD 2023-0220 for compliance will be available at 
                    <E T="03">regulations.gov</E>
                     by searching for and locating Docket No. FAA-2024-1293 after the FAA final rule is published.
                </P>
                <HD SOURCE="HD1">Airworthiness Limitation ADs Using the New Process</HD>
                <P>The FAA's process of incorporating by reference MCAI ADs as the primary source of information for compliance with corresponding FAA ADs has been limited to certain MCAI ADs (primarily those with service bulletins as the primary source of information for accomplishing the actions required by the FAA AD). However, the FAA is now expanding the process to include MCAI ADs that require a change to airworthiness limitation documents, such as airworthiness limitation sections.</P>
                <P>For these ADs that incorporate by reference an MCAI AD that changes airworthiness limitations, the FAA requirements are unchanged. Operators must revise the existing maintenance or inspection program, as applicable, to incorporate the information specified in the new airworthiness limitation document. The airworthiness limitations must be followed according to 14 CFR 91.403(c) and 91.409(e).</P>
                <P>
                    The previous format of the airworthiness limitation ADs included a paragraph that specified that no alternative actions (
                    <E T="03">e.g.,</E>
                     inspections), intervals, or CDCCLs may be used unless the actions, intervals, and CDCCLs are approved as an alternative method of compliance (AMOC) in accordance with the procedures specified in the AMOCs paragraph under “Other FAA Provisions.” This new format includes a “New Provisions for Alternative Actions, Intervals, and CDCCLs” paragraph that does not specifically refer to AMOCs, but operators may still request an AMOC to use an alternative action, interval, or CDCCL.
                </P>
                <HD SOURCE="HD1">Costs of Compliance</HD>
                <P>The FAA estimates that this AD, if adopted as proposed, would affect 9 airplanes of U.S. registry. The FAA estimates the following costs to comply with this proposed AD:</P>
                <P>The FAA estimates the total cost per operator for the retained actions from AD 2021-26-05 to be $7,650 (90 work-hours × $85 per work-hour).</P>
                <P>The FAA has determined that revising the maintenance or inspection program takes an average of 90 work-hours per operator, although the agency recognizes that this number may vary from operator to operator. Since operators incorporate maintenance or inspection program changes for their affected fleet(s), the FAA has determined that a per-operator estimate is more accurate than a per-airplane estimate. Therefore, the agency estimates the average total cost per operator to be $7,650 (90 work-hours × $85 per work-hour).</P>
                <P>The FAA estimates the total cost per operator for the new proposed actions to be $7,650 (90 work-hours × $85 per work-hour).</P>
                <HD SOURCE="HD1">Authority for This Rulemaking</HD>
                <P>
                    Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. Subtitle VII: Aviation Programs, describes in more detail the scope of the Agency's authority.
                    <PRTPAGE P="41905"/>
                </P>
                <P>The FAA is issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, Section 44701: General requirements. Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.</P>
                <HD SOURCE="HD1">Regulatory Findings</HD>
                <P>The FAA determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.</P>
                <P>For the reasons discussed above, I certify this proposed regulation:</P>
                <P>(1) Is not a “significant regulatory action” under Executive Order 12866,</P>
                <P>(2) Would not affect intrastate aviation in Alaska, and</P>
                <P>(3) Would not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.</P>
                <LSTSUB>
                    <HD SOURCE="HED">List of Subjects in 14 CFR Part 39</HD>
                    <P>Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.</P>
                </LSTSUB>
                <HD SOURCE="HD1">The Proposed Amendment</HD>
                <P>Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:</P>
                <PART>
                    <HD SOURCE="HED">PART 39—AIRWORTHINESS DIRECTIVES</HD>
                </PART>
                <AMDPAR>1. The authority citation for part 39 continues to read as follows:</AMDPAR>
                <AUTH>
                    <HD SOURCE="HED">Authority:</HD>
                    <P> 49 U.S.C. 106(g), 40113, 44701.</P>
                </AUTH>
                <SECTION>
                    <SECTNO>§ 39.13</SECTNO>
                    <SUBJECT>[Amended]</SUBJECT>
                </SECTION>
                <AMDPAR>2. The FAA amends § 39.13 by:</AMDPAR>
                <AMDPAR>a. Removing Airworthiness Directive 2021-26-05, Amendment 39-21863 (87 FR 1335, January 11, 2022); and</AMDPAR>
                <AMDPAR>b. Adding the following new airworthiness directive:</AMDPAR>
                <EXTRACT>
                    <FP SOURCE="FP-2">
                        <E T="04">Saab AB (Formerly Known as Saab AB, Support and Services):</E>
                         Docket No. FAA-2024-1293; Project Identifier MCAI-2023-01283-T.
                    </FP>
                    <HD SOURCE="HD1">(a) Comments Due Date</HD>
                    <P>The FAA must receive comments on this airworthiness directive (AD) by June 28, 2024.</P>
                    <HD SOURCE="HD1">(b) Affected ADs</HD>
                    <P>This AD replaces AD 2021-26-05, Amendment 39-21863 (87 FR 1335, January 11, 2022) (AD 2021-26-05).</P>
                    <HD SOURCE="HD1">(c) Applicability</HD>
                    <P>This AD applies to all Saab AB (formerly known as Saab AB, Support and Services) Model SAAB 2000 airplanes, certificated in any category.</P>
                    <HD SOURCE="HD1">(d) Subject</HD>
                    <P>Air Transport Association (ATA) of America Code 05, Time Limits/Maintenance Checks.</P>
                    <HD SOURCE="HD1">(e) Reason</HD>
                    <P>This AD was prompted by a determination that new or more restrictive airworthiness limitations are necessary. The FAA is issuing this AD to address among other things, fatigue cracking of principal structural elements (PSEs) and corrosion prevention and control. The unsafe condition, if not addressed, could result in reduced structural integrity of a PSE, and lead to loss of control of the airplane.</P>
                    <HD SOURCE="HD1">(f) Compliance</HD>
                    <P>Comply with this AD within the compliance times specified, unless already done.</P>
                    <HD SOURCE="HD1">(g) Retained Revision of the Existing Maintenance or Inspection Program, With a New Terminating Action</HD>
                    <P>This paragraph restates the requirements of paragraph (j) of AD 2021-26-05, with a new terminating action. Except as specified in paragraph (h) of this AD: Comply with all required actions and compliance times specified in, and in accordance with, European Union Aviation Safety Agency (EASA) AD 2021-0132, dated May 25, 2021 (EASA AD 2021-0132). Accomplishing the revision of the existing maintenance or inspection program required by paragraph (j) of this AD terminates the requirements of this paragraph.</P>
                    <HD SOURCE="HD1">(h) Retained Exceptions to EASA AD 2021-0132, With No Changes</HD>
                    <P>This paragraph restates the requirements of paragraph (h) of AD 2021-26-05, with no changes.</P>
                    <P>(1) The requirements specified in paragraphs (1) and (2) of EASA AD 2021-0132 do not apply to this AD.</P>
                    <P>(2) Paragraph (3) of EASA AD 2021-0132 specifies revising “the approved AMP [aircraft maintenance program]” within 12 months after its effective date, but this AD requires revising the existing maintenance or inspection program, as applicable, to incorporate the “limitations, tasks and associated thresholds and intervals” specified in paragraph (3) of EASA AD 2021-0132 within 90 days after February 15, 2022 (the effective date of AD 2021-26-05).</P>
                    <P>(3) The initial compliance time for doing the tasks specified in paragraph (3) of EASA AD 2021-0132 is at the applicable “associated thresholds” specified in paragraph (3) of EASA AD 2021-0132, or within 90 days after February 15, 2022 (the effective date of AD 2021-26-05), whichever occurs later.</P>
                    <P>(4) The provisions specified in paragraphs (4) and (5) of EASA AD 2021-0132 do not apply to this AD.</P>
                    <P>(5) The “Remarks” section of EASA AD 2021-0132 does not apply to this AD.</P>
                    <HD SOURCE="HD1">(i) Retained Restrictions on Alternative Actions, Intervals, and Critical Design Configuration Control Limitations (CDCCLs), With a New Exception</HD>
                    <P>
                        This paragraph restates the requirements of paragraph (l) of AD 2021-26-05, with a new exception. Except as required by paragraph (j) of this AD, after the maintenance or inspection program has been revised as required by paragraph (g) of this AD, no alternative actions (
                        <E T="03">e.g.,</E>
                         inspections), intervals, and CDCCLs are allowed unless they are approved as specified in the provisions of the “Ref. Publications” section of EASA AD 2021-0132.
                    </P>
                    <HD SOURCE="HD1">(j) New Revision of the Existing Maintenance or Inspection Program</HD>
                    <P>Except as specified in paragraph (k) of this AD: Comply with all required actions and compliance times specified in, and in accordance with, EASA AD 2023-0220, dated December 21, 2023 (EASA AD 2023-0220). Accomplishing the revision of the existing maintenance or inspection program required by this paragraph terminates the requirements of paragraph (g) of this AD.</P>
                    <HD SOURCE="HD1">(k) Exceptions to EASA AD 2023-0220</HD>
                    <P>(1) This AD does not adopt the requirements specified in paragraphs (1) and (2) of EASA AD 2023-0220.</P>
                    <P>(2) Paragraph (3) of EASA AD 2023-0220 specifies revising “the AMP” within 12 months after its effective date, but this AD requires revising the existing maintenance or inspection program, as applicable, within 90 days after the effective date of this AD.</P>
                    <P>(3) The initial compliance time for doing the tasks specified in paragraph (3) of EASA AD 2023-0220 is at the applicable “limitations” and “associated thresholds” as incorporated by the requirements of paragraph (3) of EASA AD 2023-0220, or within 90 days after the effective date of this AD, whichever occurs later.</P>
                    <P>(4) This AD does not adopt the provisions specified in paragraphs (4) and (5) of EASA AD 2023-0220.</P>
                    <P>(5) This AD does not adopt the “Remarks” section of EASA AD 2023-0220.</P>
                    <HD SOURCE="HD1">(l) New No Alternative Actions, Intervals, or CDCCLs</HD>
                    <P>
                        After the existing maintenance or inspection program has been revised as required by paragraph (j) of this AD, no alternative actions (
                        <E T="03">e.g.,</E>
                         inspections), intervals, or CDCCLs are allowed unless they are approved as specified in the provisions of the “Ref. Publications” section of EASA AD 2023-0220.
                    </P>
                    <HD SOURCE="HD1">(m) Additional AD Provisions</HD>
                    <P>
                        The following provisions also apply to this AD:
                        <PRTPAGE P="41906"/>
                    </P>
                    <P>
                        (1) 
                        <E T="03">Alternative Methods of Compliance (AMOCs):</E>
                         The Manager, International Validation Branch, FAA, has the authority to approve AMOCs for this AD, if requested using the procedures found in 14 CFR 39.19. In accordance with 14 CFR 39.19, send your request to your principal inspector or responsible Flight Standards Office, as appropriate. If sending information directly to the manager of the International Validation Branch, mail it to the address identified in paragraph (n) of this AD. Information may be emailed to: 
                        <E T="03">9-AVS-AIR-730-AMOC@faa.gov</E>
                        . Before using any approved AMOC, notify your appropriate principal inspector, or lacking a principal inspector, the manager of the responsible Flight Standards Office.
                    </P>
                    <P>
                        (2) 
                        <E T="03">Contacting the Manufacturer:</E>
                         For any requirement in this AD to obtain instructions from a manufacturer, the instructions must be accomplished using a method approved by the Manager, International Validation Branch, FAA; or EASA; or Saab AB's EASA Design Organization Approval (DOA). If approved by the DOA, the approval must include the DOA-authorized signature.
                    </P>
                    <HD SOURCE="HD1">(n) Additional Information</HD>
                    <P>
                        For more information about this AD, contact Shahram Daneshmandi, Aviation Safety Engineer, FAA, 1600 Stewart Avenue Suite 410, Westbury, NY 11590; phone: 206-231-3220; 
                        <E T="03">email: shahram.daneshmandi@faa.gov</E>
                        .
                    </P>
                    <HD SOURCE="HD1">(o) Material Incorporated by Reference</HD>
                    <P>(1) The Director of the Federal Register approved the incorporation by reference (IBR) of the service information listed in this paragraph under 5 U.S.C. 552(a) and 1 CFR part 51.</P>
                    <P>(2) You must use this service information as applicable to do the actions required by this AD, unless this AD specifies otherwise.</P>
                    <P>(3) The following service information was approved for IBR on June 18, 2024.</P>
                    <P>(i) European Union Aviation Safety Agency (EASA) AD 2023-0220, dated December 21, 2023.</P>
                    <P>(ii) [Reserved]</P>
                    <P>(4) The following service information was approved for IBR on February 15, 2022 (87 FR 1335, January 11, 2022).</P>
                    <P>(i) European Union Aviation Safety Agency (EASA) AD 2021-0132, dated May 25, 2021.</P>
                    <P>(ii) [Reserved]</P>
                    <P>
                        (5) For EASA AD 2023-0220 and EASA AD 2021-0132, contact EASA, Konrad-Adenauer-Ufer 3, 50668 Cologne, Germany; telephone +49 221 8999 000; email 
                        <E T="03">ADs@easa.europa.eu;</E>
                         website 
                        <E T="03">easa.europa.eu.</E>
                         You may find these EASA ADs on the EASA website at 
                        <E T="03">ad.easa.europa.eu.</E>
                    </P>
                    <P>(6) You may view this service information at the FAA, Airworthiness Products Section, Operational Safety Branch, 2200 South 216th St., Des Moines, WA. For information on the availability of this material at the FAA, call 206-231-3195.</P>
                    <P>
                        (7) You may view this material at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, visit 
                        <E T="03">www.archives.gov/federal-register/cfr/ibr-locations</E>
                        , or email 
                        <E T="03">fr.inspection@nara.gov</E>
                        .
                    </P>
                </EXTRACT>
                <SIG>
                    <DATED>Issued on April 26, 2024.</DATED>
                    <NAME>James D. Foltz,</NAME>
                    <TITLE>Deputy Director, Compliance &amp; Airworthiness Division, Aircraft Certification Service.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-09513 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD> BILLING CODE 4910-13-P</BILCOD>
        </PRORULE>
        <PRORULE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF TRANSPORTATION</AGENCY>
                <SUBAGY>Federal Aviation Administration</SUBAGY>
                <CFR>14 CFR Part 39</CFR>
                <DEPDOC>[Docket No. FAA-2024-1296; Project Identifier MCAI-2023-00844-R]</DEPDOC>
                <RIN>RIN 2120-AA64</RIN>
                <SUBJECT>Airworthiness Directives; Bell Textron Canada Limited Helicopters</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Aviation Administration (FAA), DOT.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of proposed rulemaking (NPRM).</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The FAA proposes to adopt a new airworthiness directive (AD) for certain Bell Textron Canada Limited Model 505 helicopters. This proposed AD was prompted by a fuel leakage discovered during fuel system crash impact testing activity. This proposed AD would require installing a grommet around the sump drain port fitting airframe hole, as specified in a Transport Canada AD, which is proposed for incorporation by reference. The FAA is proposing this AD to address the unsafe condition on these products.</P>
                </SUM>
                <EFFDATE>
                    <HD SOURCE="HED">DATES:</HD>
                    <P> The FAA must receive comments on this proposed AD by June 28, 2024.</P>
                </EFFDATE>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>You may send comments, using the procedures found in 14 CFR 11.43 and 11.45, by any of the following methods:</P>
                    <P>
                        • 
                        <E T="03">Federal eRulemaking Portal:</E>
                         Go to 
                        <E T="03">regulations.gov</E>
                        . Follow the instructions for submitting comments.
                    </P>
                    <P>
                        • 
                        <E T="03">Fax:</E>
                         (202) 493-2251.
                    </P>
                    <P>
                        • 
                        <E T="03">Mail:</E>
                         U.S. Department of Transportation, Docket Operations, M-30, West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE, Washington, DC 20590.
                    </P>
                    <P>
                        • 
                        <E T="03">Hand Delivery:</E>
                         Deliver to Mail address above between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays.
                    </P>
                    <P>
                        <E T="03">AD Docket:</E>
                         You may examine the AD docket at 
                        <E T="03">regulations.gov</E>
                         under Docket No. FAA-2024-1296; or in person at Docket Operations between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. The AD docket contains this NPRM, any comments received, and other information. The street address for Docket Operations is listed above.
                    </P>
                    <P>
                        <E T="03">Material Incorporated by Reference:</E>
                    </P>
                    <P>
                        • For Transport Canada material, contact Transport Canada, Transport Canada National Aircraft Certification, 159 Cleopatra Drive, Nepean, Ontario, K1A 0N5, CANADA; telephone 888-663-3639; email 
                        <E T="03">TC.AirworthinessDirectives-Consignesdenavigabilite.TC@tc.gc.ca</E>
                        ; internet 
                        <E T="03">tc.canada.ca/en/aviation</E>
                        . You may find the Transport Canada material on the Transport Canada website at 
                        <E T="03">wwwapps.tc.gc.ca/Saf-Sec-Sur/2/cawis-swimn/ad_qs1.aspx</E>
                        .
                    </P>
                    <P>
                        • You may view this material at the FAA, Office of the Regional Counsel, Southwest Region, 10101 Hillwood Pkwy., Room 6N-321, Fort Worth, TX 76177. For information on the availability of this material at the FAA, call (817) 222-5110. The Transport Canada material is also available at 
                        <E T="03">regulations.gov</E>
                         under Docket No. FAA-2024-1296.
                    </P>
                    <P>
                        <E T="03">Other Related Service Information:</E>
                         For Bell service information identified in this NPRM, contact Bell Textron Canada Limited, 12,800 Rue de l'Avenir, Mirabel, Quebec J7J 1R4, Canada; telephone 1-450-437-2862 or 1-800-363-8023; fax 1-450-433-0272; email 
                        <E T="03">productsupport@bellflight.com;</E>
                         or at 
                        <E T="03">bellflight.com/support/contact-support</E>
                        .
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Michael Hughlett, Aviation Safety Engineer, FAA, 1600 Stewart Avenue, Suite 410, Westbury, NY 11590; phone (817) 222-5110; email 
                        <E T="03">michael.hughlett@faa.gov</E>
                        .
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P/>
                <HD SOURCE="HD1">Comments Invited</HD>
                <P>
                    The FAA invites you to send any written relevant data, views, or arguments about this proposal. Send your comments to an address listed under 
                    <E T="02">ADDRESSES</E>
                    . Include “Docket No. FAA-2024-1296; Project Identifier MCAI-2023-00844-R” at the beginning of your comments. The most helpful comments reference a specific portion of the proposal, explain the reason for any recommended change, and include supporting data. The FAA will consider all comments received by the closing date and may amend this proposal because of those comments.
                </P>
                <P>
                    Except for Confidential Business Information (CBI) as described in the following paragraph, and other information as described in 14 CFR 11.35, the FAA will post all comments received, without change, to 
                    <E T="03">regulations.gov</E>
                    , including any personal information you provide. The agency will also post a report summarizing each substantive verbal contact received about this NPRM.
                    <PRTPAGE P="41907"/>
                </P>
                <HD SOURCE="HD1">Confidential Business Information</HD>
                <P>
                    CBI is commercial or financial information that is both customarily and actually treated as private by its owner. Under the Freedom of Information Act (FOIA) (5 U.S.C. 552), CBI is exempt from public disclosure. If your comments responsive to this NPRM contain commercial or financial information that is customarily treated as private, that you actually treat as private, and that is relevant or responsive to this NPRM, it is important that you clearly designate the submitted comments as CBI. Please mark each page of your submission containing CBI as “PROPIN.” The FAA will treat such marked submissions as confidential under the FOIA, and they will not be placed in the public docket of this NPRM. Submissions containing CBI should be sent to Michael Hughlett, Aviation Safety Engineer, FAA, 1600 Stewart Avenue, Suite 410, Westbury, NY 11590; phone (817) 222-5110; email 
                    <E T="03">michael.hughlett@faa.gov</E>
                    . Any commentary that the FAA receives that is not specifically designated as CBI will be placed in the public docket for this rulemaking.
                </P>
                <HD SOURCE="HD1">Background</HD>
                <P>Transport Canada, which is the aviation authority for Canada, has issued Transport Canada AD CF-2023-51, dated July 11, 2023 (Transport Canada AD CF-2023-51), to correct an unsafe condition on certain serial-numbered Bell Textron Canada Limited Model 505 helicopters.</P>
                <P>This proposed AD was prompted by a fuel leakage discovered during fuel system crash impact testing activity. In a certain position, the knurls on the locking sleeve of the fuel drain quick disconnect valve contacted the airframe cutout upon impact, resisting against the fuel bladder rotational action and causing deformation of the poppet, which led to the valve remaining in the partially open position and subsequent fuel leakage.</P>
                <P>The FAA is proposing this AD to prevent the fuel drain quick disconnect valve from catching on the airframe cutout and reduce the load on the valve body by preventing metal-to-metal contact following an impact. The unsafe condition, if not addressed, could result in a fuel leakage, post impact fire, injuries to occupants, and reduction in time to evacuate the helicopter.</P>
                <P>
                    You may examine Transport Canada AD CF-2023-51 in the AD docket at 
                    <E T="03">regulations.gov</E>
                    .
                </P>
                <HD SOURCE="HD1">Related Service Information Under 1 CFR Part 51</HD>
                <P>Transport Canada AD CF-2023-51 specifies installing a split plastic grommet around the periphery of the sump drain port fitting airframe cutout.</P>
                <P>
                    This material is reasonably available because the interested parties have access to it through their normal course of business or by the means identified in the 
                    <E T="02">ADDRESSES</E>
                     section.
                </P>
                <HD SOURCE="HD1">Other Related Service Information</HD>
                <P>The FAA reviewed Bell Alert Service Bulletin 505-21-21, dated June 8, 2021. For certain serial-numbered helicopters, this service information specifies procedures for installing a split plastic grommet groove around the periphery of the sump drain port fitting airframe hole cutout with the split line at the 12 o'clock position.</P>
                <HD SOURCE="HD1">FAA's Determination</HD>
                <P>These helicopters have been approved by the aviation authority of Canada and are approved for operation in the United States. Pursuant to the FAA's bilateral agreement with Canada, Transport Canada, its technical representative, has notified the FAA of the unsafe condition described in its AD. The FAA is proposing this AD after evaluating all known relevant information and determining that the unsafe condition described previously is likely to exist or develop on other helicopters of the same type design.</P>
                <HD SOURCE="HD1">Proposed AD Requirements in This NPRM</HD>
                <P>This proposed AD would require accomplishing the actions specified in Transport Canada AD CF-2023-51, described previously, as incorporated by reference, except for any differences identified as exceptions in the regulatory text of this proposed AD.</P>
                <HD SOURCE="HD1">Explanation of Required Compliance Information</HD>
                <P>
                    In the FAA's ongoing efforts to improve the efficiency of the AD process, the FAA developed a process to use some civil aviation authority (CAA) ADs as the primary source of information for compliance with requirements for corresponding FAA ADs. The FAA has been coordinating this process with manufacturers and CAAs. As a result, the FAA proposes to incorporate Transport Canada AD CF-2023-51 by reference in the FAA final rule. This proposed AD would, therefore, require compliance with Transport Canada AD CF-2023-51 in its entirety through that incorporation, except for any differences identified as exceptions in the regulatory text of this proposed AD. Using common terms that are the same as the heading of a particular section of Transport Canada AD CF-2023-51 does not mean that operators need comply only with that section. For example, where the AD requirement refers to “all required actions and compliance times,” compliance with this AD requirement is not limited to the section titled “Corrective Actions” in Transport Canada AD CF-2023-51. Service information referenced in Transport Canada AD CF-2023-51 for compliance will be available at 
                    <E T="03">regulations.gov</E>
                     under Docket No. FAA-2024-1296 after the FAA final rule is published.
                </P>
                <HD SOURCE="HD1">Costs of Compliance</HD>
                <P>The FAA estimates that this AD, if adopted as proposed, would affect 145 helicopters of U.S. Registry. Labor rates are estimated at $85 per work-hour. Based on these numbers, the FAA estimates the following costs to comply with this proposed AD.</P>
                <P>Installing a grommet around the sump drain port fitting airframe hole would take approximately 1 work-hour and parts would cost a minimal amount, for an estimated cost of $85 per helicopter and $12,325 for the U.S. fleet.</P>
                <P>The FAA has included all known costs in its cost estimate. According to the manufacturer, however, some of the costs of this proposed AD may be covered under warranty, thereby reducing the cost impact on affected operators.</P>
                <HD SOURCE="HD1">Authority for This Rulemaking</HD>
                <P>Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. Subtitle VII: Aviation Programs, describes in more detail the scope of the Agency's authority.</P>
                <P>The FAA is issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, Section 44701: General requirements. Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.</P>
                <HD SOURCE="HD1">Regulatory Findings</HD>
                <P>
                    The FAA determined that this proposed AD would not have federalism implications under Executive Order 
                    <PRTPAGE P="41908"/>
                    13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.
                </P>
                <P>For the reasons discussed above, I certify this proposed regulation:</P>
                <P>(1) Is not a “significant regulatory action” under Executive Order 12866,</P>
                <P>(2) Would not affect intrastate aviation in Alaska, and</P>
                <P>(3) Would not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.</P>
                <LSTSUB>
                    <HD SOURCE="HED">List of Subjects in 14 CFR Part 39</HD>
                    <P>Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.</P>
                </LSTSUB>
                <HD SOURCE="HD1">The Proposed Amendment</HD>
                <P>Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:</P>
                <PART>
                    <HD SOURCE="HED">PART 39—AIRWORTHINESS DIRECTIVES</HD>
                </PART>
                <AMDPAR>1. The authority citation for part 39 continues to read as follows:</AMDPAR>
                <AUTH>
                    <HD SOURCE="HED">Authority: </HD>
                    <P>49 U.S.C. 106(g), 40113, 44701.</P>
                </AUTH>
                <SECTION>
                    <SECTNO>§ 39.13</SECTNO>
                    <SUBJECT>[Amended]</SUBJECT>
                </SECTION>
                <AMDPAR>2. The FAA amends § 39.13 by adding the following new airworthiness directive:</AMDPAR>
                <EXTRACT>
                    <FP SOURCE="FP-2">
                        <E T="04">Bell Textron Canada Limited:</E>
                         Docket No. FAA-2024-1296; Project Identifier MCAI-2023-00844-R.
                    </FP>
                    <HD SOURCE="HD1">(a) Comments Due Date</HD>
                    <P>The FAA must receive comments on this airworthiness directive (AD) by June 28, 2024.</P>
                    <HD SOURCE="HD1">(b) Affected ADs</HD>
                    <P>None.</P>
                    <HD SOURCE="HD1">(c) Applicability</HD>
                    <P>This AD applies to Bell Textron Canada Limited Model 505 helicopters, certificated in any category, as identified in Transport Canada AD CF-2023-51, dated July 11, 2023 (Transport Canada AD CF-2023-51).</P>
                    <HD SOURCE="HD1">(d) Subject</HD>
                    <P>Joint Aircraft Service Component (JASC) Code: 2810, Fuel Storage.</P>
                    <HD SOURCE="HD1">(e) Unsafe Condition</HD>
                    <P>This AD was prompted by a fuel leakage discovered during fuel system crash impact testing activity. The FAA is issuing this AD to prevent the fuel drain quick disconnect valve from catching on the airframe cutout and reduce the load on the valve body by preventing metal-to-metal contact following an impact. The unsafe condition, if not addressed, could result in a fuel leakage, post impact fire, injuries to occupants, and reduction in time to evacuate the helicopter.</P>
                    <HD SOURCE="HD1">(f) Compliance</HD>
                    <P>Comply with this AD within the compliance times specified, unless already done.</P>
                    <HD SOURCE="HD1">(g) Requirements</HD>
                    <P>Except as specified in paragraph (h) of this AD: Comply with all required actions and compliance times specified in, and in accordance with, Transport Canada AD CF-2023-51.</P>
                    <HD SOURCE="HD1">(h) Exceptions to Transport Canada AD CF-2023-51</HD>
                    <P>Where Transport Canada AD CF-2023-51 refers to its effective date, this AD requires using the effective date of this AD.</P>
                    <HD SOURCE="HD1">(i) Alternative Methods of Compliance (AMOCs)</HD>
                    <P>
                        (1) The Manager, International Validation Branch, FAA, has the authority to approve AMOCs for this AD, if requested using the procedures found in 14 CFR 39.19. In accordance with 14 CFR 39.19, send your request to your principal inspector or local Flight Standards District Office, as appropriate. If sending information directly to the manager of the International Validation Branch, send it to the attention of the person identified in paragraph (j) of this AD. Information may be emailed to: 
                        <E T="03">9-AVS-AIR-730-AMOC@faa.gov</E>
                        .
                    </P>
                    <P>(2) Before using any approved AMOC, notify your appropriate principal inspector, or lacking a principal inspector, the manager of the local flight standards district office/certificate holding district office.</P>
                    <HD SOURCE="HD1">(j) Related Information</HD>
                    <P>
                        For more information about this AD, contact Michael Hughlett, Aviation Safety Engineer, FAA, 1600 Stewart Avenue, Suite 410, Westbury, NY 11590; phone (817) 222-5110; email 
                        <E T="03">michael.hughlett@faa.gov</E>
                        .
                    </P>
                    <HD SOURCE="HD1">(k) Material Incorporated by Reference</HD>
                    <P>(1) The Director of the Federal Register approved the incorporation by reference of the service information listed in this paragraph under 5 U.S.C. 552(a) and 1 CFR part 51.</P>
                    <P>(2) You must use this service information as applicable to do the actions required by this AD, unless this AD specifies otherwise.</P>
                    <P>(i) Transport Canada AD CF-2023-51, dated July 11, 2023.</P>
                    <P>(ii) [Reserved]</P>
                    <P>
                        (3) For Transport Canada AD CF-2023-51, contact Transport Canada, Transport Canada National Aircraft Certification, 159 Cleopatra Drive, Nepean, Ontario, K1A 0N5, CANADA; telephone 888-663-3639; email 
                        <E T="03">TC.AirworthinessDirectives-Consignesdenavigabilite.TC@tc.gc.ca</E>
                        ; internet 
                        <E T="03">tc.canada.ca/en/aviation</E>
                        . You may find the Transport Canada material on the Transport Canada website at 
                        <E T="03">wwwapps.tc.gc.ca/Saf-Sec-Sur/2/cawis-swimn/ad_qs1.aspx</E>
                        .
                    </P>
                    <P>(4) You may view this material at the FAA, Office of the Regional Counsel, Southwest Region, 10101 Hillwood Pkwy., Room 6N-321, Fort Worth, TX 76177. For information on the availability of this material at the FAA, call (817) 222-5110.</P>
                    <P>
                        (5) You may view this material at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, visit 
                        <E T="03">www.archives.gov/federal-register/cfr/ibr-locations</E>
                         or email 
                        <E T="03">fr.inspection@nara.gov.</E>
                    </P>
                </EXTRACT>
                <SIG>
                    <DATED>Issued on April 27, 2024.</DATED>
                    <NAME>Victor Wicklund,</NAME>
                    <TITLE>Deputy Director, Compliance &amp; Airworthiness Division, Aircraft Certification Service.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-09544 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD> BILLING CODE 4910-13-P</BILCOD>
        </PRORULE>
        <PRORULE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF TRANSPORTATION</AGENCY>
                <SUBAGY>Federal Aviation Administration</SUBAGY>
                <CFR>14 CFR Part 39</CFR>
                <DEPDOC>[Docket No. FAA-2024-1287; Project Identifier AD-2023-00992-T]</DEPDOC>
                <RIN>RIN 2120-AA64</RIN>
                <SUBJECT>Airworthiness Directives; The Boeing Company Airplanes</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Aviation Administration (FAA), DOT.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of proposed rulemaking (NPRM).</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The FAA proposes to supersede Airworthiness Directive (AD) 2012-07-06, which applies to certain The Boeing Company Model 777 airplanes. AD 2012-07-06 requires revising the maintenance program to update inspection requirements to detect fatigue cracking of principal structural elements. Since the FAA issued AD 2012-07-06, the FAA has determined that new and more restrictive airworthiness limitations are necessary. This proposed AD would retain the requirements of AD 2012-07-06 until the new or more restrictive airworthiness limitations are incorporated. The FAA is proposing this AD to address the unsafe condition on these products.</P>
                </SUM>
                <EFFDATE>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The FAA must receive comments on this proposed AD by June 28, 2024.</P>
                </EFFDATE>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>You may send comments, using the procedures found in 14 CFR 11.43 and 11.45, by any of the following methods:</P>
                    <P>
                        • 
                        <E T="03">Federal eRulemaking Portal:</E>
                         Go to 
                        <E T="03">regulations.gov</E>
                        . Follow the instructions for submitting comments.
                    </P>
                    <P>
                        • 
                        <E T="03">Fax:</E>
                         202-493-2251.
                    </P>
                    <P>
                        • 
                        <E T="03">Mail:</E>
                         U.S. Department of Transportation, Docket Operations, M-30, West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE, Washington, DC 20590.
                        <PRTPAGE P="41909"/>
                    </P>
                    <P>
                        • 
                        <E T="03">Hand Delivery:</E>
                         Deliver to Mail address above between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays.
                    </P>
                    <P>
                        <E T="03">AD Docket:</E>
                         You may examine the AD docket at 
                        <E T="03">regulations.gov</E>
                         under Docket No. FAA-2024-1287; or in person at Docket Operations between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. The AD docket contains this NPRM, any comments received, and other information. The street address for Docket Operations is listed above.
                    </P>
                    <P>
                        <E T="03">Material Incorporated by Reference:</E>
                    </P>
                    <P>
                        • For Boeing material, contact Boeing Commercial Airplanes, Attention: Contractual &amp; Data Services (C&amp;DS), 2600 Westminster Blvd., MC 110-SK57, Seal Beach, CA 90740-5600; telephone 562-797-1717; website 
                        <E T="03">myboeingfleet.com</E>
                        .
                    </P>
                    <P>
                        • You may view this service information at the FAA, Airworthiness Products Section, Operational Safety Branch, 2200 South 216th St., Des Moines, WA. For information on the availability of this material at the FAA, call 206-231-3195. It is also available at 
                        <E T="03">regulations.gov</E>
                         by searching for and locating Docket No. FAA-2024-1287.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Luis Cortez-Muniz, Aviation Safety Engineer, FAA, 2200 South 216th St., Des Moines, WA 98198; phone: 206-231-3958; email: 
                        <E T="03">Luis.A.Cortez-Muniz@faa.gov</E>
                        .
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P/>
                <HD SOURCE="HD1">Comments Invited</HD>
                <P>
                    The FAA invites you to send any written relevant data, views, or arguments about this proposal. Send your comments to an address listed under 
                    <E T="02">ADDRESSES</E>
                    . Include “Docket No. FAA-2024-1287; Project Identifier AD-2023-00992-T” at the beginning of your comments. The most helpful comments reference a specific portion of the proposal, explain the reason for any recommended change, and include supporting data. The FAA will consider all comments received by the closing date and may amend the proposal because of those comments.
                </P>
                <P>
                    Except for Confidential Business Information (CBI) as described in the following paragraph, and other information as described in 14 CFR 11.35, the FAA will post all comments received, without change, to 
                    <E T="03">regulations.gov</E>
                    , including any personal information you provide. The agency will also post a report summarizing each substantive verbal contact received about this proposed AD.
                </P>
                <HD SOURCE="HD1">Confidential Business Information</HD>
                <P>
                    CBI is commercial or financial information that is both customarily and actually treated as private by its owner. Under the Freedom of Information Act (FOIA) (5 U.S.C. 552), CBI is exempt from public disclosure. If your comments responsive to this NPRM contain commercial or financial information that is customarily treated as private, that you actually treat as private, and that is relevant or responsive to this NPRM, it is important that you clearly designate the submitted comments as CBI. Please mark each page of your submission containing CBI as “PROPIN.” The FAA will treat such marked submissions as confidential under the FOIA, and they will not be placed in the public docket of this NPRM. Submissions containing CBI should be sent to Luis Cortez-Muniz, Aviation Safety Engineer, FAA, 2200 South 216th St., Des Moines, WA 98198; phone: 206-231-3958; email: 
                    <E T="03">Luis.A.Cortez-Muniz@faa.gov</E>
                    . Any commentary that the FAA receives that is not specifically designated as CBI will be placed in the public docket for this rulemaking.
                </P>
                <HD SOURCE="HD1">Background</HD>
                <P>The FAA issued AD 2012-07-06, Amendment 39-17012 (77 FR 21429, April 10, 2012) (AD 2012-07-06), for The Boeing Company Model 777-200, -200LR, -300, -300ER, and 777F series airplanes with an original airworthiness certificate or original export certificate of airworthiness issued before September 1, 2010. AD 2012-07-06 was prompted by a new revision to the airworthiness limitations (AWLs) of the maintenance planning document (MPD). AD 2012-07-06 requires revising the maintenance program to update inspection requirements to detect fatigue cracking of principal structural elements (PSEs). The agency issued AD 2012-07-06 to ensure that fatigue cracking of various PSEs is detected and corrected; such fatigue cracking could adversely affect the structural integrity of these airplanes. AD 2012-07-06 does not apply to airplanes with an original airworthiness certificate or original export certificate of airworthiness issued on or after September 1, 2010, since those airplanes were delivered with Instructions for Continued Airworthiness containing the AWLs mandated by AD 2012-07-06.</P>
                <HD SOURCE="HD1">Actions Since AD 2012-07-06 Was Issued</HD>
                <P>Since the FAA issued AD 2012-07-06, new and more restrictive airworthiness limitations are necessary. The inspections and life limits have been updated in the latest revision to the AWLs of the MPD and the damage tolerance rating (DTR) Check Form Document. The DTR document defines inspection options and the damage tolerance ratings necessary to develop the structural inspections required by the AWLs. Airplanes with an original airworthiness certificate or original export certificate of airworthiness issued after January 5, 2024, were delivered with Instructions for Continued Airworthiness containing these new and revised requirements.</P>
                <HD SOURCE="HD1">FAA's Determination</HD>
                <P>The FAA is issuing this NPRM after determining that the unsafe condition described previously is likely to exist or develop on other products of the same type design.</P>
                <HD SOURCE="HD1">Related Service Information Under 1 CFR Part 51</HD>
                <P>The FAA reviewed Section 9, Airworthiness Limitations (AWLs) and Certification Maintenance Requirements (CMRs), D622W001-9, Revision December 2022, of the Boeing 777-200/200LR/300/300ER/777F Maintenance Planning Data (MPD) Document. Subsection B, Airworthiness Limitations-Structural Inspections and Subsection C, Airworthiness Limitations-Structural Safe-Life Limits, of this service information contains airworthiness limitations for structural inspections and structural life limits, among other limitations.</P>
                <P>The FAA also reviewed Boeing 777-200/200LR/300/300ER/777F Damage Tolerance Rating (DTR) Check Form Document, D622W001-DTR, dated December 2022. This service information provides the DTR check forms and the procedure for their use.</P>
                <P>This proposed AD would also require Section 9, “Airworthiness Limitations (AWLs) and Certification Maintenance Requirements (CMRs),” D622W001-9, Revision July 2011, of the Boeing 777 MPD Document, which the Director of the Federal Register approved for incorporation by reference as of May 15, 2012 (77 FR 21429, April 10, 2012).</P>
                <P>
                    This service information is reasonably available because the interested parties have access to it through their normal course of business or by the means identified in the 
                    <E T="02">ADDRESSES</E>
                     section.
                </P>
                <HD SOURCE="HD1">Proposed AD Requirements in This NPRM</HD>
                <P>
                    For airplanes with an original airworthiness certificate or original export certificate of airworthiness issued before September 1, 2010, this proposed AD would retain all the requirements of AD 2012-07-06. For airplanes with an original airworthiness certificate or original export certificate of airworthiness issued before January 4, 
                    <PRTPAGE P="41910"/>
                    2024, this proposed AD would require revising the existing maintenance or inspection program to incorporate new and more restrictive airworthiness limitations, which would then terminate the retained requirements of AD 2012-07-06. This proposed AD would also require sending inspection results to Boeing.
                </P>
                <HD SOURCE="HD1">Differences Between This Proposed AD and the Service Information</HD>
                <P>This proposed AD would require that the reports specified in Section 9, Airworthiness Limitations (AWLs) and Certification Maintenance Requirements (CMRs), D622W001-9, Revision December 2022, of the Boeing 777-200/200LR/300/300ER/777F Maintenance Planning Data (MPD) Document; and Boeing 777-200/200LR/300/300ER/777F Damage Tolerance Rating (DTR) Check Form Document, D622W001-DTR, dated December 2022, be submitted within 10 days after the airplane is returned to service, instead of 10 days after each individual finding as specified in the documents.</P>
                <HD SOURCE="HD1">Costs of Compliance</HD>
                <P>The FAA estimates that this AD, if adopted as proposed, would affect 325 airplanes of U.S. registry. The FAA estimates the following costs to comply with this proposed AD:</P>
                <P>The FAA estimates the total cost per operator for the retained actions from AD 2012-07-06 to be $7,650 (90 work-hours × $85 per work-hour).</P>
                <P>The FAA has determined that revising the existing maintenance or inspection program takes an average of 90 work-hours per operator, although the FAA recognizes that this number may vary from operator to operator. Since operators incorporate maintenance or inspection program changes for their affected fleet(s), the FAA has determined that a per-operator estimate is more accurate than a per-airplane estimate.</P>
                <P>The FAA estimates the total cost per operator for the new proposed actions to be $7,650 (90 work × hours × $85 per work-hour).</P>
                <GPOTABLE COLS="4" OPTS="L2,i1" CDEF="s25,r100,12C,12C">
                    <TTITLE>On-Condition Costs</TTITLE>
                    <BOXHD>
                        <CHED H="1">Action</CHED>
                        <CHED H="1">Labor cost</CHED>
                        <CHED H="1">Parts cost</CHED>
                        <CHED H="1">
                            Cost per 
                            <LI>product</LI>
                        </CHED>
                    </BOXHD>
                    <ROW>
                        <ENT I="01">Reporting</ENT>
                        <ENT>1 work-hour × $85 per hour = $85</ENT>
                        <ENT>$0</ENT>
                        <ENT>$85</ENT>
                    </ROW>
                </GPOTABLE>
                <HD SOURCE="HD1">Paperwork Reduction Act</HD>
                <P>A federal agency may not conduct or sponsor, and a person is not required to respond to, nor shall a person be subject to a penalty for failure to comply with a collection of information subject to the requirements of the Paperwork Reduction Act unless that collection of information displays a currently valid OMB Control Number. The OMB Control Number for this information collection is 2120-0056. Public reporting for this collection of information is estimated to be approximately 1 hour per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, completing and reviewing the collection of information. All responses to this collection of information are mandatory. Send comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden to: Information Collection Clearance Officer, Federal Aviation Administration, 10101 Hillwood Parkway, Fort Worth, TX 76177-1524.</P>
                <HD SOURCE="HD1">Authority for This Rulemaking</HD>
                <P>Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, Section 106, describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the Agency's authority.</P>
                <P>The FAA is issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, Section 44701, General requirements. Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.</P>
                <HD SOURCE="HD1">Regulatory Findings</HD>
                <P>The FAA has determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.</P>
                <P>For the reasons discussed above, I certify that the proposed regulation:</P>
                <P>(1) Is not a “significant regulatory action” under Executive Order 12866,</P>
                <P>(2) Would not affect intrastate aviation in Alaska, and</P>
                <P>(3) Would not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.</P>
                <LSTSUB>
                    <HD SOURCE="HED">List of Subjects in 14 CFR Part 39</HD>
                    <P>Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.</P>
                </LSTSUB>
                <HD SOURCE="HD1">The Proposed Amendment</HD>
                <P>Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:</P>
                <PART>
                    <HD SOURCE="HED">PART 39—AIRWORTHINESS DIRECTIVES</HD>
                </PART>
                <AMDPAR>1. The authority citation for part 39 continues to read as follows:</AMDPAR>
                <AUTH>
                    <HD SOURCE="HED">Authority: </HD>
                    <P>49 U.S.C. 106(g), 40113, 44701.</P>
                </AUTH>
                <SECTION>
                    <SECTNO>§ 39.13</SECTNO>
                    <SUBJECT>[Amended]</SUBJECT>
                </SECTION>
                <AMDPAR>2. The FAA amends § 39.13 by:</AMDPAR>
                <AMDPAR>a. Removing Airworthiness Directive (AD) 2012-07-06, Amendment 39-17012 (77 FR 21429, April 10, 2012), and</AMDPAR>
                <AMDPAR>b. Adding the following new AD:</AMDPAR>
                <EXTRACT>
                    <FP SOURCE="FP-2">
                        <E T="04">The Boeing Company:</E>
                         Docket No. FAA-2024-1287; Project Identifier AD-2023-00992-T.
                    </FP>
                    <HD SOURCE="HD1">(a) Comments Due Date</HD>
                    <P>The FAA must receive comments on this airworthiness directive (AD) by June 28, 2024.</P>
                    <HD SOURCE="HD1">(b) Affected ADs</HD>
                    <P>This AD replaces AD 2012-07-06, Amendment 39-17012 (77 FR 21429, April 10, 2012) (AD 2012-07-06).</P>
                    <HD SOURCE="HD1">(c) Applicability</HD>
                    <P>
                        This AD applies to The Boeing Company Model 777-200, -200LR, -300, -300ER, and 777F series airplanes, certificated in any 
                        <PRTPAGE P="41911"/>
                        category, with an original airworthiness certificate or original export certificate of airworthiness issued before January 5, 2024.
                    </P>
                    <HD SOURCE="HD1">(d) Subject</HD>
                    <P>Air Transport Association (ATA) of America Code27, Flight Controls; 28, Fuel; 32, Landing Gear; 52, Doors; 53, Fuselage; 54, Nacelles/Pylons; 55, Stabilizers; 57, Wings.</P>
                    <HD SOURCE="HD1">(e) Unsafe Condition</HD>
                    <P>This AD was prompted by new revisions to the airworthiness limitations of the maintenance planning document and damage tolerance rating check form document. The FAA is issuing this AD to address fatigue cracking of various principal structural elements. The unsafe condition, if not addressed, could adversely affect the structural integrity of the airplane.</P>
                    <HD SOURCE="HD1">(f) Compliance</HD>
                    <P>Comply with this AD within the compliance times specified, unless already done.</P>
                    <HD SOURCE="HD1">(g) Retained Revision of Maintenance Program With No Changes</HD>
                    <P>This paragraph restates the requirements of paragraph (g) of AD 2012-07-06, with no changes. For airplanes with an original airworthiness certificate or original export certificate of airworthiness issued before September 1, 2010: Comply with the requirements of paragraphs (g)(1) through (3) of this AD. Accomplishing the revision of the existing maintenance or inspection program required by paragraph (i) of this AD terminates the requirements of this paragraph.</P>
                    <P>(1) Within 12 months after May 15, 2012 (the effective date of AD 2012-07-06), revise the maintenance program by incorporating the information in Subsection B, Airworthiness Limitations-Structural Inspections, of Section 9, “Airworthiness Limitations (AWLs) and Certification Maintenance Requirements (CMRs),” D622W001-9, Revision July 2011, of the Boeing 777 Maintenance Planning Data (MPD) Document, except as provided by paragraph (h) of this AD.</P>
                    <P>(2) The initial compliance time for the inspections is within the applicable times specified in Subsection B, Airworthiness Limitations-Structural Inspections, of Section 9, of “Airworthiness Limitations (AWLs) and Certification Maintenance Requirements (CMRs),” D622W001-9, Revision July 2011, of the Boeing 777 Maintenance Planning Data (MPD) Document, or within 18 months after May 15, 2012 (the effective date of AD 2012-07-06), whichever occurs later, or within the applicable time specified in Subsection B, Airworthiness Limitations-Structural Inspections, of Section 9, “Airworthiness Limitations (AWLs) and Certification Maintenance Requirements (CMRs),” D622W001-9, Revision July 2011, of the Boeing 777 Maintenance Planning Data (MPD) Document, from the time of installation for new parts.</P>
                    <P>(3) Reports specified in Section 9, “Airworthiness Limitations (AWLs) and Certification Maintenance Requirements (CMRs),” D622W001-9, Revision July 2011, of the Boeing 777 Maintenance Planning Data (MPD) Document may be submitted within 10 days after the airplane is returned to service, instead of 10 days after each individual finding as specified in this document.</P>
                    <HD SOURCE="HD1">(h) Retained Alternative Inspections and Inspection Intervals With an Additional Exception</HD>
                    <P>This paragraph restates the requirements of paragraph (h) of AD 2012-07-06, with an additional exception. After accomplishing the actions required by paragraph (g) of this AD, no alternative inspections or inspection intervals may be used unless the alternative inspection or interval is required by paragraph (i) of this AD or approved as an alternative method of compliance (AMOC) in accordance with the procedures specified in paragraph (k) of this AD.</P>
                    <HD SOURCE="HD1">(i) Revision of Maintenance or Inspection Program</HD>
                    <P>(1) Within 12 months after the effective date of this AD, revise the existing maintenance or inspection program by incorporating the information in Subsection B, Airworthiness Limitations-Structural Inspections and Subsection C, Airworthiness Limitations-Structural Safe-Life Limits, of Section 9, Airworthiness Limitations (AWLs) and Certification Maintenance Requirements (CMRs), D622W001-9, Revision December 2022, of the Boeing 777-200/200LR/300/300ER/777F Maintenance Planning Data (MPD) Document; and in Boeing 777-200/200LR/300/300ER/777F Damage Tolerance Rating (DTR) Check Form Document, D622W001-DTR, dated December 2022.</P>
                    <P>(2) The initial compliance time for the tasks is within the applicable times specified in Subsection B, Airworthiness Limitations-Structural Inspections and Subsection C, Airworthiness Limitations-Structural Safe-Life Limits, of Section 9, Airworthiness Limitations (AWLs) and Certification Maintenance Requirements (CMRs), D622W001-9, Revision December 2022, of the Boeing 777-200/200LR/300/300ER/777F MPD Document; and in Boeing 777-200/200LR/300/300ER/777F DTR Check Form Document, D622W001-DTR, dated December 2022, or within 12 months after the effective date of this AD, whichever occurs later.</P>
                    <P>(3) Reports specified in Section 9, Airworthiness Limitations (AWLs) and Certification Maintenance Requirements (CMRs), D622W001-9, Revision December 2022, of the Boeing 777-200/200LR/300/300ER/777F MPD Document; and in Boeing 777-200/200LR/300/300ER/777F DTR Check Form Document, D622W001-DTR, dated December 2022 may be submitted within 10 days after the airplane is returned to service, instead of 10 days after each individual finding as specified in the documents.</P>
                    <HD SOURCE="HD1">(j) Alternative Inspections and Inspection Intervals</HD>
                    <P>After accomplishing the actions required by paragraph (i) of this AD, no alternative inspections or inspection intervals may be used unless the alternative inspection or interval is approved as an AMOC in accordance with the procedures specified in paragraph (k) of this AD.</P>
                    <HD SOURCE="HD1">(k) Alternative Methods of Compliance (AMOCs)</HD>
                    <P>
                        (1) The Manager, AIR-520, Continued Operational Safety Branch, FAA, has the authority to approve AMOCs for this AD, if requested using the procedures found in 14 CFR 39.19. In accordance with 14 CFR 39.19, send your request to your principal inspector or responsible Flight Standards Office, as appropriate. If sending information directly to the manager of the certification office, send it to the attention of the person identified in paragraph (l) of this AD. Information may be emailed to: 
                        <E T="03">AMOC@faa.gov</E>
                        .
                    </P>
                    <P>(2) Before using any approved AMOC, notify your appropriate principal inspector, or lacking a principal inspector, the manager of the responsible Flight Standards Office.</P>
                    <P>(3) An AMOC that provides an acceptable level of safety may be used for any repair, modification, or alteration required by this AD if it is approved by The Boeing Company Organization Designation Authorization (ODA) that has been authorized by the Manager, AIR-520, Continued Operational Safety Branch, FAA, to make those findings. To be approved, the repair method, modification deviation, or alteration deviation must meet the certification basis of the airplane, and the approval must specifically refer to this AD.</P>
                    <P>(4) AMOCs approved for AD 2012-07-06 are approved as AMOCs for the corresponding provisions of paragraph (g) of this AD.</P>
                    <P>(5) AMOCs approved for repairs and alterations for AD 2012-07-06 are approved as AMOCs for the corresponding provisions of paragraph (i) of this AD. All other AMOCs approved for AD 2012-07-06 are not approved as AMOCs for the corresponding provisions of paragraph (i) of this AD.</P>
                    <HD SOURCE="HD1">(l) Related Information</HD>
                    <P>
                        For more information about this AD, contact Luis Cortez-Muniz, Aviation Safety Engineer, FAA, 2200 South 216th St., Des Moines, WA 98198; phone: 206-231-3958; email: 
                        <E T="03">Luis.A.Cortez-Muniz@faa.gov</E>
                        .
                    </P>
                    <HD SOURCE="HD1">(m) Material Incorporated by Reference</HD>
                    <P>(1) The Director of the Federal Register approved the incorporation by reference (IBR) of the service information listed in this paragraph under 5 U.S.C. 552(a) and 1 CFR part 51.</P>
                    <P>(2) You must use this service information as applicable to do the actions required by this AD, unless this AD specifies otherwise.</P>
                    <P>(3) The following service information was approved for IBR on [DATE 35 DAYS AFTER PUBLICATION OF THE FINAL RULE].</P>
                    <P>(i) Section 9, Airworthiness Limitations (AWLs) and Certification Maintenance Requirements (CMRs), D622W001-9, Revision December 2022, of the Boeing 777-200/200LR/300/300ER/777F Maintenance Planning Data (MPD) Document.</P>
                    <P>(ii) Boeing 777-200/200LR/300/300ER/777F Damage Tolerance Rating (DTR) Check Form Document, D622W001-DTR, dated December 2022.</P>
                    <P>
                        (4) The following service information was approved for IBR on May 15, 2012 (77 FR 21429, April 10, 2012).
                        <PRTPAGE P="41912"/>
                    </P>
                    <P>(i) Section 9, “Airworthiness Limitations (AWLs) and Certification Maintenance Requirements (CMRs),” D622W001-9, Revision July 2011, of the Boeing 777 Maintenance Planning Data (MPD) Document.</P>
                    <P>(ii) [Reserved]</P>
                    <P>
                        (5) For Boeing material, contact Boeing Commercial Airplanes, Attention: Contractual &amp; Data Services (C&amp;DS), 2600 Westminster Blvd., MC 110-SK57, Seal Beach, CA 90740-5600; telephone 562-797-1717; website 
                        <E T="03">myboeingfleet.com</E>
                        .
                    </P>
                    <P>(6) You may view this service information at the FAA, Airworthiness Products Section, Operational Safety Branch, 2200 South 216th St., Des Moines, WA. For information on the availability of this material at the FAA, call 206-231-3195.</P>
                    <P>
                        (7) You may view this material at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, visit 
                        <E T="03">www.archives.gov/federal-register/cfr/ibr-locations</E>
                         or email 
                        <E T="03">fr.inspection@nara.gov.</E>
                    </P>
                </EXTRACT>
                <SIG>
                    <DATED>Issued on April 26, 2024.</DATED>
                    <NAME>James D. Foltz,</NAME>
                    <TITLE>Deputy Director, Compliance &amp; Airworthiness Division, Aircraft Certification Service.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-09545 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD> BILLING CODE 4910-13-P</BILCOD>
        </PRORULE>
        <PRORULE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF THE TREASURY</AGENCY>
                <CFR>31 CFR Part 1</CFR>
                <RIN>RIN 1505-AC84</RIN>
                <SUBJECT>Privacy Act of 1974; Exempting a System of Records From Certain Requirements</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Internal Revenue Service, Department of the Treasury.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of proposed rulemaking (NPRM).</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>In accordance with the requirements of the Privacy Act of 1974, as amended, the Department of the Treasury gives notice of a proposed amendment to this part to exempt a new Internal Revenue Service (IRS) system of records entitled “IRS 34.018 Treasury/IRS Insider Risk Management Records” from certain provisions of the Privacy Act.</P>
                </SUM>
                <EFFDATE>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Comments must be received no later than June 13, 2024.</P>
                </EFFDATE>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>You may submit comments, identified by docket number, Regulatory Information Number (RIN), and title, by any of the following methods:</P>
                    <P>
                        Federal e-rulemaking portal 
                        <E T="03">http://www.regulations.gov.</E>
                         Follow the Instructions for making comments; or U.S. Mail: Deputy Assistant Secretary for Privacy, Transparency, and Records, Department of the Treasury, 1500 Pennsylvania Avenue NW, Washington, DC 20220, Attention: Revisions to Privacy Act Systems of Records.
                    </P>
                    <P>
                        <E T="03">Instructions:</E>
                         For electronic submissions, type TREAS-DO-2024-0003 in the search field on the 
                        <E T="03">regulations.gov</E>
                         homepage to find this notice and submit comments. All submissions received must include the agency docket number or RIN. All comments received electronically or on paper will be posted without change to 
                        <E T="03">http://www.regulations.gov,</E>
                         including personal information provided.
                    </P>
                    <P>
                        <E T="03">Docket:</E>
                         For access to the docket to read background documents, or comments received, go to 
                        <E T="03">http://www.regulations.gov.</E>
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Chief Risk Officer, Internal Revenue Service, Office of the Chief Risk Officer, Enterprise Risk Management, 1111 Constitution Ave. NW, Washington, DC 20224-0002; telephone: (801) 612-4815.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>Under 5 U.S.C. 552a(k)(2) (31 CFR 1.36), the head of any agency may promulgate rules to exempt any system of records within the agency from certain provisions of the Privacy Act if the system is investigatory material compiled for law enforcement purposes that is not within the scope of 5 U.S.C. 552a(j)(2) (which applies to agencies and components thereof that perform as their principal function any activity pertaining to the enforcement of criminal laws).</P>
                <P>The IRS is hereby giving notice of a proposed rule to exempt “34.018, Treasury/IRS Insider Risk Management Records” from certain provisions of the Privacy Act of 1974, pursuant to 5 U.S.C. 552a(k)(2). The proposed exemptions are from sections 552a(c)(3), (d)(1)-(4), (e)(1), (e)(4)(G), (e)(4)(H), (e)(4)(I), and (f) because the system contains investigatory material compiled for law enforcement purposes. The following are the reasons this system of records maintained by the IRS may be exempted pursuant to 5 U.S.C. 552a(k)(2):</P>
                <P>1. 5 U.S.C. 552a(c)(3) requires an agency to make accountings of disclosures of a record available to the individual named in the record upon their request. Any such accountings must state the date, nature, and purpose of each disclosure of the record and the name and address of the recipient. Applying this subsection could alert the subject of an investigation of an actual or potential criminal, civil, or regulatory violation to the existence of that investigation and reveal investigative interest on the part of the IRS. Disclosure of an accounting would therefore present a serious impediment to the IRS, Treasury, and other law enforcement agencies by permitting the subject of record to impede investigations, to tamper with witnesses or evidence, and to avoid detection or apprehension, which would undermine the entire investigative process. In the case of a delinquent account, such release might enable the subject of the investigation to dissipate assets before levy. When an investigation has been completed, information on disclosures made may continue to be exempted if the fact that an investigation occurred remains sensitive after completion.</P>
                <P>2. 5 U.S.C. 552a(d)(1), (e)(4)(H) and (f)(2), (3) and (5) grant individuals access to records pertaining to them. An exemption from these provisions is appropriate because providing access to such records could inform the subject of an investigation of an actual or potential criminal, civil, or regulatory violation to the existence of that investigation and reveal investigative interest on the part of the IRS or another bureau or agency. Access to the records could permit the subject of a record to impede the investigation, to tamper with witnesses or evidence, and to avoid detection or apprehension. In addition, permitting access to such information could disclose security-sensitive information that could be detrimental to the IRS. Agency rules are exempt from the individual access provisions of subsection 5 U.S.C. 552a for this system of records, therefore, the IRS and Treasury are not required to establish requirements, rules or procedures with respect to such access.</P>
                <P>
                    3. 5 U.S.C. 552a(d)(2), (3) and (4), (e)(4)(H), and (f)(4) permit an individual to request amendment of a record pertaining to them and require the agency to provide notice on how to request an amendment, and provide procedures for reviewing, making determinations and the appeal process concerning amendments. Because these provisions depend on the individual having access to their records, and since this rule exempts the IRS system of records from the provisions of 5 U.S.C. 552a relating to access to records for the reasons set forth above, these provisions do not apply. Furthermore, an exemption from this requirement is appropriate because allowing individuals to amend certain records that pertain to them would interfere with the mechanism of ongoing investigations and law enforcement activities and would impose an unreasonable administrative burden by requiring investigations to be continually reinvestigated. In addition, permitting amendment to such information could disclose security-
                    <PRTPAGE P="41913"/>
                    sensitive information that could be detrimental to the IRS.
                </P>
                <P>4. 5 U.S.C. 552a(e)(1) requires an agency to maintain in its records only such information about an individual as is relevant and necessary to accomplish a purpose of the agency required by statute or Executive order. Maintenance of information, as defined in 5 U.S.C. 552a(a)(3), includes the collection and dissemination of information. An exemption from this provision is therefore appropriate because its application would require the IRS to make determinations at the time of collection about the relevance and necessity of collected information. Speculative determinations about the relevance and necessity of collected information may be impossible to determine immediately, as information that initially appears irrelevant and unnecessary, often may prove particularly valuable, therefore application of this provision to the system of records could impair the Department's ability to collect, utilize and disseminate valuable law enforcement information.</P>
                <P>5. 5 U.S.C. 552a(e)(4)(G) and (f)(1) enable individuals to inquire whether a system of records contains records pertaining to them An exemption from these provisions is appropriate because alerting individuals involved in illegal activity that the IRS has, or does not have, information that could lead to them being identified for investigation allows them to take steps to avoid detection, begin, continue, or resume illegal conduct upon learning that they are not identified in the system of records; or destroy evidence needed to prove the violation, all of which could undermine the IRS's ability to carry out its mission.</P>
                <P>6. 5 U.S.C. 552a(e)(4)(I) requires an agency to publish a general notice listing the categories of sources for information contained in a system of records. The application of this provision to the system of records could disclose investigative techniques and cause informants to refuse to give full information for fear their identities as sources could be disclosed, subjecting them to threats or reprisals. This could compromise the IRS's ability to complete or continue investigations or to share useful information to law enforcement agencies.</P>
                <P>The IRS is also hereby giving notice of a proposed rule to exempt “34.018 Treasury/IRS Insider Risk Management Records” from certain provisions of the Privacy Act of 1974, pursuant to 5 U.S.C. 552a(k)(5). The proposed exemptions are from provisions 552a(c)(3), (d)(1)-(4), (e)(1), (e)(4)(G), (e)(4)(H), (e)(4)(I), and (f) because the system contains investigatory material compiled solely for the purpose of determining suitability, eligibility, or qualifications for Federal civilian employment, Federal contracts, or access to classified information.. The following are the reasons this system of records maintained by the IRS may be exempted pursuant to 5 U.S.C. 552a(k)(5):</P>
                <P>1. The sections of 5 U.S.C. 552a from which the systems of records are exempt generally provide for individuals' access to or amendment of records. Such access may reveal the identity of a confidential source under an express promise that the source's identity would be held in confidence. This could hinder the IRS's ability to obtain future confidential sources. In addition, 5 U.S.C. 552a(e)(1) is unduly restrictive in requiring the IRS to maintain only such information about an individual as is relevant and necessary to accomplish a purpose of the agency as required by a statute or executive order, since it is often not until well after the investigation that it is possible to determine the relevance and necessity of particular information.</P>
                <P>2. IRS claims the exemptions 5 U.S.C. 552a(j)(2) and (k)(2) if any investigatory material contained in the above-named system becomes involved in criminal or civil matters.</P>
                <HD SOURCE="HD1">Procedural Matters</HD>
                <P>As required by Executive Order 12866, it has been determined that this proposed rule is not a significant regulatory action, and therefore, does not require a regulatory impact analysis. The regulation will not have a substantial direct effect on the States, on the relationship between the Federal Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this proposed rule does not have federalism implications under Executive Order 13132.</P>
                <P>Pursuant to the requirements of the Regulatory Flexibility Act, 5 U.S.C. 601-612, it is hereby certified that these regulations will not have a significant economic impact on a substantial number of small entities. The proposed rule imposes no duties or obligations on small entities.</P>
                <P>In accordance with the provisions of the Paperwork Reduction Act of 1995, the Department of the Treasury has determined that this proposed rule would not impose new recordkeeping, application, reporting, or other types of information collection requirements.</P>
                <LSTSUB>
                    <HD SOURCE="HED">List of Subjects in 31 CFR Part 1</HD>
                    <P>Privacy.</P>
                </LSTSUB>
                <P>The Department of the Treasury proposes to amend part 1 of title 31 of the Code of Federal Regulations as follows:</P>
                <PART>
                    <HD SOURCE="HED">PART 1—DISCLOSURE OF RECORDS</HD>
                </PART>
                <AMDPAR>1. The authority citation for part 1 continues to read as follows:</AMDPAR>
                <AUTH>
                    <HD SOURCE="HED">Authority:</HD>
                    <P> 5 U.S.C. 301, 552, 552a, 553; 31 U.S.C. 301, 321; 31 U.S.C. 3717.</P>
                </AUTH>
                <AMDPAR>2. Amend § 1.36 by:</AMDPAR>
                <AMDPAR>a. In paragraph (g)(1)(vii), adding an entry to table 16 to paragraph (g)(1)(vii) in alpha-numeric order; and</AMDPAR>
                <AMDPAR>b. In paragraph (k)(1)(iii), adding an entry to table 23 to paragraph (k)(1)(iii) in alpha-numeric order.</AMDPAR>
                <P>The additions read as follows:</P>
                <SECTION>
                    <SECTNO>§ 1.36</SECTNO>
                    <SUBJECT>Systems exempt in whole or in part from provisions of the Privacy Act and this part.</SUBJECT>
                    <STARS/>
                    <P>(g) * * *</P>
                    <P>(1) * * *</P>
                    <P>
                        (vii) 
                        <E T="03">Internal Revenue Service.</E>
                    </P>
                    <GPOTABLE COLS="2" OPTS="L1,i1" CDEF="s100,r100">
                        <TTITLE>
                            Table 16 to Paragraph 
                            <E T="01">(g)(1)(vii)</E>
                        </TTITLE>
                        <BOXHD>
                            <CHED H="1">No.</CHED>
                            <CHED H="1">Name of system</CHED>
                        </BOXHD>
                        <ROW>
                            <ENT I="22"> </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="28">*         *         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">IRS 34.018</ENT>
                            <ENT>Treasury/IRS Insider Risk Management Records.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="28">*         *         *         *         *         *         *</ENT>
                        </ROW>
                    </GPOTABLE>
                    <STARS/>
                    <P>(k) * * *</P>
                    <P>
                        (1) * * *
                        <PRTPAGE P="41914"/>
                    </P>
                    <P>(iii) Internal Revenue Service.</P>
                    <GPOTABLE COLS="2" OPTS="L1,i1" CDEF="s100,r100">
                        <TTITLE>
                            Table 23 to Paragraph 
                            <E T="01">(k)(1)(iii)</E>
                        </TTITLE>
                        <BOXHD>
                            <CHED H="1">No.</CHED>
                            <CHED H="1">Name of system</CHED>
                        </BOXHD>
                        <ROW>
                            <ENT I="01">IRS 34.018</ENT>
                            <ENT>Treasury/IRS Insider Risk Management Records.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="22"> </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="28">*         *         *         *         *         *         *</ENT>
                        </ROW>
                    </GPOTABLE>
                    <STARS/>
                </SECTION>
                <SIG>
                    <NAME>Ryan Law,</NAME>
                    <TITLE>Deputy Assistant Secretary Privacy, Transparency, and Records, U.S. Department of the Treasury.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-09696 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4810-AK-P</BILCOD>
        </PRORULE>
        <PRORULE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Coast Guard</SUBAGY>
                <CFR>33 CFR Part 100</CFR>
                <DEPDOC>[Docket Number USCG-2024-0207]</DEPDOC>
                <RIN>RIN 1625-AA08</RIN>
                <SUBJECT>Special Local Regulation; Clear Lake, Clear Creek, TX</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Coast Guard, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of proposed rulemaking.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Coast Guard is proposing to amend its regulations for annual marine events in the Sector Houston-Galveston area of responsibility. This proposed rulemaking would prohibit persons and vessels not participating in the event from being within the specified zones unless authorized by the Captain of the Port Houston-Galveston or a designated representative. We invite your comments on this proposed rulemaking.</P>
                </SUM>
                <EFFDATE>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Comments and related material must be received by the Coast Guard on or before June 13, 2024.</P>
                </EFFDATE>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        You may submit comments identified by docket number USCG-2024-0207 using the Federal Decision-Making Portal at 
                        <E T="03">https://www.regulations.gov.</E>
                         See the “Public Participation and Request for Comments” portion of the 
                        <E T="02">SUPPLEMENTARY INFORMATION</E>
                         section for further instructions on submitting comments. This notice of proposed rulemaking with its plain-language, 100-word-or-less proposed rule summary will be available in this same docket.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        If you have questions about this proposed rulemaking, call or email Lieutenant Junior Grade Linda I Duncan, Sector Houston-Galveston Waterways Management Division, U.S. Coast Guard; telephone 713-398-5823, email 
                        <E T="03">houstonwwm@uscg.mil.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P/>
                <HD SOURCE="HD1">I. Table of Abbreviations</HD>
                <EXTRACT>
                    <FP SOURCE="FP-1">CFR Code of Federal Regulations</FP>
                    <FP SOURCE="FP-1">DHS Department of Homeland Security</FP>
                    <FP SOURCE="FP-1">FR Federal Register</FP>
                    <FP SOURCE="FP-1">NPRM Notice of proposed rulemaking</FP>
                    <FP SOURCE="FP-1">§ Section </FP>
                    <FP SOURCE="FP-1">U.S.C. United States Code</FP>
                </EXTRACT>
                <HD SOURCE="HD1">II. Background, Purpose, and Legal Basis</HD>
                <P>On March 4, 2024, an organization notified the Coast Guard that it will be conducting the 17th annual high speed boat race from 8 a.m. to noon on June 21, 2024. The boat race is to be held in the waters of Clear Lake, in Clear Creek, TX. The Captain of the Port Houston-Galveston (COTP) has determined that potential hazards associated with the power boat race will be a safety concern for anyone within the Pre-Stage Zone, Approach Zone, Course Run Zone, and Shut-Down Zone before, during, and after the scheduled event.</P>
                <P>The Texas Outlaw Challenge Boat Race, in Clear Lake, Clear Creek, TX, occurs on an annually recurring basis. Historically, the Coast Guard has established annual temporary final regulations for this marine event. This proposed rule would consistently inform the public in a timely manner through permanent publication in Title 33 of the Code of Federal Regulations. This proposed rule would add a recurring marine event requiring a special local regulation to TABLE 3 of 33 CFR 100.801—Sector Houston-Galveston Annual and Recurring Marine Events. By establishing permanent regulations for this marine event, the Coast Guard would eliminate the need to establish temporary rules on an annual basis and thereby limit the costs associated with cumulative regulations. The purpose of this rulemaking is to protect personnel, vessels, and the marine environment in the navigable waters within the Pre-Stage Zone, Approach Zone, Course Run Zone, and Shut-Down Zone before, during and after the annual Texas Outlaw Challenge power boat race in Clear Lake, TX. The Coast Guard is proposing this rulemaking under authority in 46 U.S.C. 70041.</P>
                <P>
                    In order to allow a 30-day public comment period, the Coast Guard anticipates issuing a final rule with an effective date less than 30 days after publication in the 
                    <E T="04">Federal Register</E>
                    . Should that occur, we will explain our good cause for doing so in that publication, as required by 5 U.S.C. 553(d)(3).
                </P>
                <HD SOURCE="HD1">III. Discussion of Proposed Rule</HD>
                <P>The COTP is proposing to establish a special local regulation from 8 a.m. to noon on a Friday of the third week of June. The special local regulation will encompass five different zones to include the Pre-Stage Zone, Approach Zone, Course Run Zone, Shut-Down Zone, and the Spectator Zone as described below:</P>
                <P>Pre-Stage Zone: This area is the pre-staging area for participating vessels to line up. It will include all waters within the following areas 29°33.13 N, 095°01.84 W thence to 29°33.12 N, 095°01.89 W thence to 29°33.23 N, 095°01.96 W thence to 29°33.13 N, 095°01.84 W.</P>
                <P>
                    <E T="03">Approach Zone:</E>
                      
                    <FR>1/4</FR>
                     mile distance required for participating vessels to obtain the minimum 40 mph requirement for course entry. This will be a straight line to begin at approximately 29°33.256 N, 095°01.89 W and end at approximately 29°33.33 N, 095°02.15 W.
                </P>
                <P>
                    <E T="03">Course Run Zone:</E>
                      
                    <FR>3/4</FR>
                     mile distance where participating vessels will conduct their high-speed run. This will be a straight line to begin at approximately 29°33.33 N, 095°02.16 W and end at approximately 29°33.53 N, 095°02.98 W.
                </P>
                <P>
                    <E T="03">Shut-Down Zone:</E>
                     1 mile distance where participating vessels will be allowed to slow their speeds back to an idle. This will be a straight line to begin at approximately 29°33.53 N, 095°02.98 W and end at approximately 29°33.74 N, 095°04.1 W.
                </P>
                <P>
                    <E T="03">Spectator Zone:</E>
                     All vessels that will be viewing the event will be required to stay within a designated area. The sponsor is responsible for marking the spectator zone with 4 buoys on the outer 
                    <PRTPAGE P="41915"/>
                    corners and ensuring that all vessels within the area are anchored and remain in the area during all ongoing high-speed runs. The following coordinates are the approximate location of the Spectator Zone: 29°33.15 N, 95°02.34 W, thence to 29°33.11 N, 95°02.35 W, thence to 29°33.21 N, 95°02.50 W, thence to 29°33.15 N, 95°02.53 W.
                </P>
                <P>No vessel or person would be permitted to enter the established zones without obtaining permission from the on-water Safety-Officer or designated representative.</P>
                <P>The term “designated representative” means Coast Guard Patrol Commanders, including Coast Guard coxswains, petty officers, and other officers operating Coast Guard vessels, and Federal, state, and local officers designated by or assisting the Captain of the Port Houston-Galveston in the enforcement of the regulated areas.</P>
                <P>The regulatory text we are proposing appears at the end of this document.</P>
                <HD SOURCE="HD1">IV. Regulatory Analyses</HD>
                <P>We developed this proposed rule after considering numerous statutes and Executive orders related to rulemaking. Below we summarize our analyses based on a number of these statutes and Executive orders, and we discuss First Amendment rights of protestors.</P>
                <HD SOURCE="HD2">A. Regulatory Planning and Review</HD>
                <P>Executive Orders 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits. This NPRM has not been designated a “significant regulatory action,” under section 3(f) of Executive Order 12866, as amended by Executive Order 14094 (Modernizing Regulatory Review). Accordingly, the NPRM has not been reviewed by the Office of Management and Budget (OMB).</P>
                <P>This regulatory action determination is based on the size, location, duration, and time-of-day of the safety zone. Vessel traffic would be able to safely transit around this safety zone which would impact a small, designated area of Clear Lake for 4 hours during the morning when vessel traffic is normally low. Moreover, the Coast Guard would issue a Broadcast Notice to Mariners via VHF-FM marine channel 16 about the zone, and the rule would allow vessels to seek permission to enter the zone.</P>
                <HD SOURCE="HD2">B. Impact on Small Entities</HD>
                <P>The Regulatory Flexibility Act of 1980, 5 U.S.C. 601-612, as amended, requires Federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000. The Coast Guard certifies under 5 U.S.C. 605(b) that this proposed rule would not have a significant economic impact on a substantial number of small entities.</P>
                <P>While some owners or operators of vessels intending to transit the safety zone may be small entities, for the reasons stated in section IV.A above, this proposed rule would not have a significant economic impact on any vessel owner or operator.</P>
                <P>
                    If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this proposed rule would have a significant economic impact on it, please submit a comment (see 
                    <E T="02">ADDRESSES</E>
                    ) explaining why you think it qualifies and how and to what degree this rule would economically affect it.
                </P>
                <P>
                    Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), we want to assist small entities in understanding this proposed rule. If the proposed rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please call or email the person listed in the 
                    <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                     section. The Coast Guard will not retaliate against small entities that question or complain about this proposed rule or any policy or action of the Coast Guard.
                </P>
                <HD SOURCE="HD2">C. Collection of Information</HD>
                <P>This proposed rule would not call for a new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).</P>
                <HD SOURCE="HD2">D. Federalism and Indian Tribal Governments</HD>
                <P>A rule has implications for federalism under Executive Order 13132 (Federalism), if it has a substantial direct effect on the States, on the relationship between the National Government and the States, or on the distribution of power and responsibilities among the various levels of government. We have analyzed this proposed rule under that Order and have determined that it is consistent with the fundamental federalism principles and preemption requirements described in Executive Order 13132.</P>
                <P>
                    Also, this proposed rule does not have tribal implications under Executive Order 13175 (Consultation and Coordination with Indian Tribal Governments) because it would not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes. If you believe this proposed rule has implications for federalism or Indian tribes, please call or email the person listed in the 
                    <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                     section.
                </P>
                <HD SOURCE="HD2">E. Unfunded Mandates Reform Act</HD>
                <P>The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this proposed rule would not result in such an expenditure, we do discuss the potential effects of this proposed rule elsewhere in this preamble.</P>
                <HD SOURCE="HD2">F. Environment</HD>
                <P>
                    We have analyzed this proposed rule under Department of Homeland Security Directive 023-01, Rev. 1, associated implementing instructions, and Environmental Planning COMDTINST 5090.1 (series), which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (42 U.S.C. 4321-4370f), and have made a preliminary determination that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This proposed rule involves a marine event and special local regulation lasting only 4 hours that would prohibit entry withing 100 feet of the boat course. Normally such actions are categorically excluded from further review under paragraph L61 of Appendix A, Table 1 of DHS Instruction Manual 023-01-001-01, Rev. 1. A preliminary Record of Environmental Consideration supporting this determination is available in the docket. For instructions on locating the docket, see the 
                    <E T="02">ADDRESSES</E>
                     section of this preamble. We seek any comments or information that may lead to the discovery of a significant environmental impact from this proposed rule.
                </P>
                <HD SOURCE="HD2">G. Protest Activities</HD>
                <P>
                    The Coast Guard respects the First Amendment rights of protesters. Protesters are asked to call or email the person listed in the 
                    <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                     section to 
                    <PRTPAGE P="41916"/>
                    coordinate protest activities so that your message can be received without jeopardizing the safety or security of people, places, or vessels.
                </P>
                <HD SOURCE="HD1">V. Public Participation and Request for Comments</HD>
                <P>We view public participation as essential to effective rulemaking and will consider all comments and material received during the comment period. Your comment can help shape the outcome of this rulemaking. If you submit a comment, please include the docket number for this rulemaking, indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation.</P>
                <P>
                    <E T="03">Submitting comments.</E>
                     We encourage you to submit comments through the Federal Decision-Making Portal at 
                    <E T="03">https://www.regulations.gov.</E>
                     To do so, go to 
                    <E T="03">https://www.regulations.gov,</E>
                     type USCG-2024-0207 in the search box and click “Search.” Next, look for this document in the Search Results column, and click on it. Then click on the Comment option. If you cannot submit your material by using 
                    <E T="03">https://www.regulations.gov,</E>
                     call or email the person in the 
                    <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                     section of this proposed rule for alternate instructions.
                </P>
                <P>
                    <E T="03">Viewing material in docket.</E>
                     To view documents mentioned in this proposed rule as being available in the docket, find the docket as described in the previous paragraph, and then select “Supporting &amp; Related Material” in the Document Type column. Public comments will also be placed in our online docket and can be viewed by following instructions on the 
                    <E T="03">https://www.regulations.gov</E>
                     Frequently Asked Questions web page. Also, if you click on the Dockets tab and then the proposed rule, you should see a “Subscribe” option for email alerts. The option will notify you when comments are posted, or a final rule is published.
                </P>
                <P>We review all comments received, but we will only post comments that address the topic of the proposed rule. We may choose not to post off-topic, inappropriate, or duplicate comments that we receive.</P>
                <P>
                    <E T="03">Personal information.</E>
                     We accept anonymous comments. Comments we post to 
                    <E T="03">https://www.regulations.gov</E>
                     will include any personal information you have provided. For more about privacy and submissions to the docket in response to this document, see DHS's eRulemaking System of Records notice (85 FR 14226, March 11, 2020).
                </P>
                <LSTSUB>
                    <HD SOURCE="HED">List of Subjects in 33 CFR Part 100</HD>
                    <P>Harbors, Marine Safety, Navigation (water), Reporting and recordkeeping requirements, Security measures, Waterways.</P>
                </LSTSUB>
                <P>For the reasons discussed in the preamble, the Coast Guard is proposing to amend 33 CFR part 100 as follows:</P>
                <PART>
                    <HD SOURCE="HED">PART 100—SAFETY OF LIFE ON NAVIGABLE WATERS</HD>
                </PART>
                <AMDPAR>1. The authority citation for part 100 continues to read as follows:</AMDPAR>
                <AUTH>
                    <HD SOURCE="HED">Authority:</HD>
                    <P> 46 U.S.C. 70041; 33 CFR 1.05-1.</P>
                </AUTH>
                <AMDPAR>2. In § 100.801, amend Table 3, by adding item 7 to read as follows: </AMDPAR>
                <SECTION>
                    <SECTNO>§ 100.801</SECTNO>
                    <SUBJECT>Annual Marine Events in the Eighth Coast Guard District.</SUBJECT>
                    <STARS/>
                    <GPOTABLE COLS="4" OPTS="L1,p1,8/9,i1" CDEF="s50,r50,r50,r100">
                        <TTITLE>Table 3 of § 100.801—Sector Houston-Galveston Annual and Recurring Marine Events</TTITLE>
                        <BOXHD>
                            <CHED H="1"> </CHED>
                            <CHED H="1"> </CHED>
                            <CHED H="1"> </CHED>
                            <CHED H="1"> </CHED>
                        </BOXHD>
                        <ROW>
                            <ENT I="22"> </ENT>
                        </ROW>
                        <ROW>
                            <ENT I="28">*         *         *         *         *         *         *</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">7. Friday of the 3rd week of June</ENT>
                            <ENT>Texas Outlaw Challenge/Offshore Thunder Productions LLC</ENT>
                            <ENT>Clear Lake, TX</ENT>
                            <ENT>All waters within 100 feet of the Pre-Stage Zone including all waters within the following areas 29°33.13 N, 095°01.84 W, thence to 29°33.12 N, 095°01.89 W, thence to 29°33.23 N, 095°01.96 W, thence to 29°33.13 N, 095°01.84 W; the Approach Zone comprised of a straight line to begin at approximately 29°33.256 N, 095°01.89 W and end at approximately 29°33.33 N, 095°02.15 W; the Course Run Zone comprised of a straight line to begin at approximately 29°33.33 N, 095°02.16 W and end at approximately 29°33.53 N, 095°02.98 W; the Shut-Down Zone comprised of a straight line to begin at approximately 29°33.53 N, 095°02.98 W and end at approximately 29°33.74 N, 095°04.1 W; and the Spectator Zone located within the following coordinates; 29°33.15 N, 95°02.34 W, thence to 29°33.11 N, 95°02.35 W, thence to 29°33.21 N, 95°02.50 W, thence to 29°33.15 N, 95°02.53 W.</ENT>
                        </ROW>
                    </GPOTABLE>
                </SECTION>
                <SIG>
                    <DATED>Dated: May 7, 2024.</DATED>
                    <NAME>Keith M. Donohue,</NAME>
                    <TITLE>Captain, U.S. Coast Guard, Captain of the Port Sector Houston-Galveston.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10216 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9110-04-P</BILCOD>
        </PRORULE>
        <PRORULE>
            <PREAMB>
                <PRTPAGE P="41917"/>
                <AGENCY TYPE="N">DEPARTMENT OF COMMERCE</AGENCY>
                <SUBAGY>National Oceanic and Atmospheric Administration</SUBAGY>
                <CFR>50 CFR Part 223</CFR>
                <DEPDOC>[Docket No. 240508-0132]</DEPDOC>
                <RIN>RIN 0648-BM49</RIN>
                <SUBJECT>Endangered and Threatened Wildlife and Plants; Protective Regulations for the Oceanic Whitetip Shark (Carcharhinus longimanus)</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Department of Commerce.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Proposed rule; request for comments; notice of availability of a draft environmental assessment.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>
                        We, NMFS, are proposing to issue protective regulations under section 4(d) of the Endangered Species Act (ESA) for the conservation of the threatened oceanic whitetip shark (
                        <E T="03">Carcharhinus longimanus</E>
                        ). The proposed regulations would apply all of the prohibitions listed under ESA sections 9(a)(1)(A) through 9(a)(1)(G) for the species, with limited exceptions for scientific research and law enforcement activities that contribute to the conservation of the species. In addition, we are announcing the availability of a draft environmental assessment (EA) that analyzes the environmental impacts of promulgating these regulations. Finally, we solicit comments from the public and all interested parties regarding this proposed rule and the draft EA.
                    </P>
                </SUM>
                <EFFDATE>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Comments on this proposed rule must be received by July 15, 2024.</P>
                </EFFDATE>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        A plain language summary of this proposed rule is available at 
                        <E T="03">https://www.regulations.gov/docket/NOAA-NMFS-2023-0117.</E>
                         You may submit comments on the proposed rule, identified by NOAA-NMFS-2023-0117 by the following method:
                    </P>
                    <P>
                        • 
                        <E T="03">Electronic Submissions:</E>
                         Submit all electronic comments via the Federal e-Rulemaking Portal. Go to 
                        <E T="03">https://www.regulations.gov</E>
                         and enter NOAA-NMFS-2023-0117 in the Search box. Click on the “Comment” icon, complete the required fields, and enter or attach your comments.
                    </P>
                    <P>
                        <E T="03">Instructions:</E>
                         Comments sent by any other method, to any other address or individual, or received after the end of the comment period, may not be considered by NMFS. All comments received are a part of the public record and will generally be posted for public viewing on 
                        <E T="03">https://www.regulations.gov</E>
                         without change. All personal identifying information (
                        <E T="03">e.g.,</E>
                         name and address), confidential business information, or otherwise sensitive information submitted voluntarily by the sender will be publicly accessible. NMFS will accept anonymous comments (enter “N/A” in the required fields if you wish to remain anonymous).
                    </P>
                    <P>
                        The proposed rule and other reference materials regarding this determination are available electronically at 
                        <E T="03">https://www.fisheries.noaa.gov/species/oceanic-whitetip-shark#conservation-management.</E>
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Adrienne Lohe, NMFS Office of Protected Resources, 301-427-8442.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">Background</HD>
                <P>The prohibitions listed under section 9(a)(1) of the ESA automatically apply when a species is listed as endangered, but not when a species is listed as threatened. In the case of a species listed as threatened, the Secretary of Commerce (Secretary) shall issue such regulations as deemed necessary and advisable to provide for the conservation of the species (16 U.S.C. 1533(d)). The Secretary may by regulation prohibit with respect to any threatened species any or all acts prohibited under section 9(a)(1). Section 9(a)(1) of the ESA prohibits any person subject to the jurisdiction of the United States from: (a) importing any such species into, or exporting any such species from the United States; (b) taking any such species within the United States or the territorial sea of the United States; (c) taking any such species upon the high seas; (d) possessing, selling, delivering, carrying, transporting, or shipping, by any means whatsoever, any such species that was illegally taken; (e) delivering, receiving, carrying, transporting, or shipping in interstate or foreign commerce, by any means whatsoever and in the course of commercial activity, any such species; (f) selling or offering for sale in interstate or foreign commerce any such species; or (g) violating any regulation pertaining to such species or to any threatened species of fish or wildlife (16 U.S.C. 1538(a)(1)). The ESA defines “take” as to harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in any such conduct (16 U.S.C. 1532(19)). The term “harm” is defined in our regulations as any act which kills or injures fish or wildlife. Such an act may include significant habitat modification or degradation that results in death or injury of wildlife by significantly impairing essential behavioral patterns, including breeding, spawning, rearing, migrating, feeding, or sheltering (50 CFR 222.102). The term “harm” is used in this proposed rule as defined in the regulations.</P>
                <P>
                    The final rule to list the oceanic whitetip shark (
                    <E T="03">Carcharhinus longimanus</E>
                    ) as a threatened species under the ESA was published on January 30, 2018, and became effective March 1, 2018 (83 FR 4153). The proposed and final rules to list the species as threatened (81 FR 96304, December 29, 2016; 83 FR 4153, January 30, 2018), the Oceanic Whitetip Status Review Report (Young 
                    <E T="03">et al.</E>
                     2017), and the Draft Recovery Status Review (NMFS 2023) provide extensive information on the status of the oceanic whitetip shark and the threats facing this species. We relied heavily on these documents while developing this proposed rule, and provide a brief summary of the species' status and threats below.
                </P>
                <P>
                    The oceanic whitetip shark is a highly migratory, pelagic species distributed in tropical and subtropical waters globally. The species is relatively long-lived, and has low to moderate productivity relative to other shark species. Although the oceanic whitetip shark is currently thought to consist of a single population, some population structuring (
                    <E T="03">i.e.,</E>
                     genetic differentiation between population segments) is evident, particularly between the Atlantic and Indo-Pacific (Ruck 2016; Camargo 
                    <E T="03">et al.</E>
                     2016). Historical fisheries data and observations suggest that the species was once among the most common and ubiquitous shark species in tropical waters around the world (NMFS 2023). More recently, however, numerous lines of evidence from all three major ocean basins (Atlantic, Pacific, and Indian Oceans) suggest that the oceanic whitetip shark has experienced significant historical declines of varying magnitudes over the past several decades, and that these declines are likely ongoing (NMFS 2023). Rigby 
                    <E T="03">et al.</E>
                     (2019) estimated a median global population reduction at 98-100 percent over three generation lengths (61.2 years). This is the only global trend estimate available for the oceanic whitetip shark. The following threats have been identified as contributing to the threatened status of the species: incidental bycatch in commercial fisheries (particularly pelagic longlines (PLL), purse seines, and gillnets), international trade of oceanic whitetip shark fins, and inadequate regulatory mechanisms (management) to address these threats. There are several other stressors that are of lesser concern but 
                    <PRTPAGE P="41918"/>
                    that may work synergistically to negatively affect the population viability of oceanic whitetip sharks (
                    <E T="03">e.g.,</E>
                     effects of climate change, pollutants, recreational fisheries).
                </P>
                <P>In our listing determination for the species we concluded that, within the jurisdiction of the United States, regulations to control for overutilization of oceanic whitetip sharks in U.S. waters, including fisheries management plans with quotas and trip limits, species-specific retention prohibitions in PLL gear, and finning regulations, were not in and of themselves inadequate such that they were contributing to the global extinction risk of the species (81 FR 96304, December 29, 2016). Further, NMFS has recently added the oceanic whitetip shark to the prohibited retention list for all U.S. Atlantic shark fisheries (89 FR 278, January 3, 2024). However, retention of oceanic whitetip sharks is not prohibited in all gear types or fisheries, and other forms of take beyond retention are not prohibited.</P>
                <HD SOURCE="HD1">Application of Section 9 Prohibitions to the Oceanic Whitetip Shark</HD>
                <P>Based on the preceding information, we are proposing to apply all of the prohibitions listed under ESA sections 9(a)(1)(A) through (G) to the species, with limited exceptions. This will contribute to the conservation of the species by ensuring that the United States is not impeding the recovery of the species. We are proposing limited exceptions to the prohibitions on import, export, and take; these limited exceptions are more fully described in the next section.</P>
                <P>
                    Section 9(a)(1)(A) prohibits the import and export of endangered species to or from the United States. The international shark fin trade was identified as a significant threat to the oceanic whitetip shark in both the final listing of the species (83 FR 4153, January 30, 2018) and the Draft Recovery Status Review (NMFS 2023). Although the oceanic whitetip shark is not generally targeted in fisheries, the high value of oceanic whitetip shark fins creates an incentive for opportunistic retention and finning of oceanic whitetip sharks when caught, and is the main economic driver of mortality of this species in commercial fisheries throughout its global range. The United States makes up a small proportion of the global shark fin trade (Ferretti 
                    <E T="03">et al.</E>
                     2020), and shark finning has been illegal in U.S. waters for many years. Additionally, the Shark Fin Sales Elimination Act, enacted as section 5946 of the National Defense Authorization Act for Fiscal Year 2023 (117 H.R. 7776, Pub. L. 117-263, Dec. 23, 2022), recently prohibited the possessing, acquiring, receiving, transporting, offering for sale, selling, or purchasing a shark fin or a product containing a shark fin in the United States, with limited exceptions. However, prohibition of the import and export of oceanic whitetip sharks to or from the United States through this rule, if finalized, would serve to further deter illegal trade and transshipment activity within and through the United States.
                </P>
                <P>Section 9(a)(1)(B) of the ESA prohibits the take of endangered species within the United States or the territorial seas of the United States, and section 9(a)(1)(C) prohibits the take of endangered species upon the high seas by any person subject to the jurisdiction of the United States. As stated previously, “take” under the ESA means to harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or to attempt to engage in any such conduct. Take of oceanic whitetip sharks may be intentional or incidental, may occur during the course of commercial or recreational activities, and may result in direct and indirect impacts to an individual shark. Because much of the range of the oceanic whitetip shark occurs outside U.S. jurisdiction, it is important that protective regulations also prohibit take on the high seas by any person subject to U.S. jurisdiction. Protecting oceanic whitetip sharks from take, whether intentional or incidental, would help preserve the species' populations occurring in U.S. waters as well as on the high seas, and slow the rate of population decline.</P>
                <P>Sections 9(a)(1)(D), (E), and (F) of the ESA prohibit, among other things, the possession, sale, and transport of endangered species that are taken illegally or that are entered into interstate or foreign commerce. The extension of these prohibitions to the oceanic whitetip shark would serve as a further deterrent to illegal trade in its fins or other parts.</P>
                <P>Lastly, we are proposing to extend the section 9(a)(1)(G) prohibition against violating this and any other regulations we promulgate pertaining to the oceanic whitetip shark.</P>
                <HD SOURCE="HD1">Summary of Exceptions to Section 9 Prohibitions</HD>
                <P>The ESA allows for specific exceptions to the section 9 prohibitions through interagency consultations as prescribed by ESA section 7 or permits issued pursuant to ESA section 10. If this proposed rule becomes final and the section 9 prohibitions are extended to the threatened oceanic whitetip shark, the following exceptions would also apply.</P>
                <P>Section 7 of the ESA requires all Federal agencies to consult with us on actions they fund, authorize, or carry out that may affect species listed under the ESA (16 U.S.C. 1536(a)(2)). NMFS consults on a range of activities conducted, funded, or authorized by Federal agencies, including but not limited to fishery regulations and scientific research activities. Incidental take of the oceanic whitetip shark that results from federally conducted, funded, or authorized activities for which section 7 consultations are completed would not constitute violations of section 9 prohibitions against take, provided the activities are conducted in accordance with all reasonable and prudent measures (RPMs) and terms and conditions contained in any biological opinion issued by NMFS.</P>
                <P>Sections 10(a)(1)(A) and (B) of the ESA provide us with the authority to grant exceptions to the ESA's prohibitions for certain activities. Section 10(a)(1)(A) allows NMFS to permit any action otherwise prohibited by section 9 for scientific purposes or to enhance the propagation or survival of the affected species. We issue scientific research and enhancement permits to Federal and non-Federal entities conducting research or conservation activities that involve take of a listed species, in exception to any section 9 prohibitions. Section 10(a)(1)(B) allows NMFS to issue incidental take permits to non-Federal entities performing activities that may incidentally take a listed species in the course of an otherwise lawful activity; these permits provide an exception to the section 9(a)(1)(B) prohibitions.</P>
                <P>We have decided to propose exceptions to the ESA section 9(a)(1)(A), (B), and (C) prohibitions for the oceanic whitetip shark, to apply in certain circumstances described below. We are proposing exceptions to these prohibitions for two classes of activities that provide for the conservation of the species. Specifically, and under specified conditions described below, we propose to except: (1) scientific research activities from the section 9(a)(1)(A), (B), and (C) prohibitions; and (2) law enforcement activities from the section 9(a)(1)(B) take prohibitions. These exceptions are described in detail in the following sections.</P>
                <HD SOURCE="HD2">Exception to Prohibitions for Scientific Research Activities</HD>
                <P>
                    Currently, there are many data gaps related to the biology, life history, ecology, movement patterns, habitat 
                    <PRTPAGE P="41919"/>
                    use, and population structure of the oceanic whitetip shark. Scientific research to fill these data gaps is critical for improving our understanding of the species' conservation status and threats facing the species, assessing the effectiveness of current and future management measures, measuring recovery progress, and ultimately conserving the species. The species' life history parameters and population structure may be investigated through the collection and analysis of tissue samples (
                    <E T="03">e.g.,</E>
                     fin clip, tissue plug, blood) from live animals. Determination of life history parameters may also be accomplished through the collection and analysis of biological samples (
                    <E T="03">e.g.,</E>
                     vertebrae, reproductive organs, blood, and other internal organs) from animals that previously suffered mortality unrelated to the need to obtain biological samples (
                    <E T="03">i.e.,</E>
                     sample collection from salvaged carcasses, or samples taken by fisheries observers or scientists from oceanic whitetip sharks dead at haulback). Reproductive information may be gleaned using ultrasonography techniques on live female sharks that may or may not be pregnant. Data on movements and habitat use may be obtained through application of video cameras/Crittercams, as well as tagging (
                    <E T="03">e.g.,</E>
                     conventional, acoustic, satellite, biologgers, physiological), release, and recapture of live animals. Some of these research activities require targeted and/or incidental capture or handling of individual sharks during fishing activities in order to take biological samples, apply various tracking tags, and/or conduct other research activities. Therefore, these and other types of research activities that will contribute to the species' conservation would require conditional exceptions from the take prohibitions. We propose an exception from the section 9(a)(1)(B) and (C) prohibitions for scientific research activities when the following conditions are met: (1) the scientific research activities are carried out by or in collaboration with a research institution; state, tribal, or federal agency; or other scientific organization in a good faith effort to advance the conservation and/or recovery of the species; (2) the scientific research activities are intended to involve only non-lethal take, 
                    <E T="03">i.e.,</E>
                     no individuals may be intentionally killed for the purposes of scientific research under this exception; and (3) the scientific research activities are carried out in accordance with all other applicable laws and regulations. If these conditions are met, scientific research activities resulting in take would not constitute a violation of the prohibitions, and an ESA section 10(a)(1)(A) permit would not be required.
                </P>
                <P>We also propose an exception from the section 9(a)(1)(A) prohibitions on import and/or export when the following conditions are met: (1) the import or export is accompanied by proper permits issued under the Convention on International Trade in Endangered Species of Wild Fauna and Flora (CITES) indicating that the trade is for the purposes of scientific research; and (2) the import or export is carried out in accordance with all other applicable laws and regulations. If these conditions are met, import and/or export for the purposes of scientific research would not constitute a violation of the section 9(a)(1)(A) prohibitions, and an ESA section 10(a)(1)(A) permit would not be required.</P>
                <HD SOURCE="HD2">Exception to Prohibitions for Law Enforcement Activities</HD>
                <P>There may be instances in which law enforcement officials or management authorities, including any employee or designee of NMFS or of any other governmental entity that has co-management authority for the oceanic whitetip shark, may need to take an oceanic whitetip shark when acting in the course of their official duties. We propose that the employee or designee, when acting in the course of official duties, be authorized to take an oceanic whitetip shark without an ESA section 10(a)(1)(A) permit if such action is necessary in the following circumstances: to aid a sick, injured, entangled, or stranded oceanic whitetip shark, to dispose of a dead oceanic whitetip shark, or to salvage a dead oceanic whitetip shark (or parts or samples thereof) that may be useful for scientific study.</P>
                <HD SOURCE="HD1">Identification of Those Activities That Would Constitute a Violation of Section 9 of the ESA</HD>
                <P>On July 1, 1994, NMFS and the U.S. Fish and Wildlife Service (FWS) published a policy (59 FR 34272) that requires us to identify, to the extent known at the time a species is listed, those activities that would or would not be considered likely to result in a violation of section 9 of the ESA. The intent of this policy is to increase public awareness of the effect of a listing on proposed and ongoing activities within a species' range. Because we did not apply any of the section 9 prohibitions to the oceanic whitetip shark at the time of listing, we will now identify the activities that are likely to result in a violation of the proposed prohibitions in this proposed rule. Based on the best scientific and commercial data available, we conclude that the following categories of activities are those likely to result in a violation of the ESA section 9 prohibitions. Whether a violation results from a particular activity, however, is entirely dependent upon the facts and circumstances of each incident. The mere fact that an activity may fall within one of these categories does not mean that the specific activity will result in a violation; due to such factors as location and scope, specific actions may not result in direct or indirect adverse effects on the species. Further, an activity not listed here may result in a violation. However, the following types of activities are those that are likely to violate the prohibitions in section 9 that we propose to extend to the oceanic whitetip shark through this action:</P>
                <P>1. Fishing activity that results in take of oceanic whitetip sharks, unless authorized by an incidental take statement issued through a biological opinion pursuant to section 7 of the ESA or permitted through section 10 of the ESA.</P>
                <P>2. Interstate or foreign commerce in oceanic whitetip sharks or parts or products thereof.</P>
                <P>3. Import or export of oceanic whitetip sharks, or parts or products thereof, unless under an ESA section 10 permit or subject to the scientific research activity exception in this proposed rule.</P>
                <P>
                    This non-exhaustive list provides examples of the types of activities that are likely to violate this proposed rule, if finalized. Identification of these activities is intended to help people identify actions with a high risk of violating the ESA, such that they can be avoided, and to encourage efforts to recover the oceanic whitetip shark. Persons or entities concluding that their activity is likely to violate the ESA are encouraged to immediately adjust or terminate that activity to avoid violations and to seek authorization under: (a) an ESA section 10 incidental take permit; (b) an ESA section 10 research and enhancement permit; or (c) an ESA section 7 consultation. The public is encouraged to contact us (see 
                    <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                    ) for assistance in determining whether circumstances at a particular location, involving these or any other activities, might constitute a violation of this proposed rule, if finalized.
                </P>
                <P>
                    We find that, based on the best available information, the following actions will not result in a violation of the section 9 prohibitions that we 
                    <PRTPAGE P="41920"/>
                    propose to extend to the species through this action:
                </P>
                <P>1. Activities that result in incidental take authorized by an incidental take statement issued through a biological opinion pursuant to section 7 of the ESA or permitted through section 10 of the ESA.</P>
                <P>2. Collection, handling, and possession of oceanic whitetip sharks and specimens thereof that are acquired lawfully in accordance with an ESA section 10 permit or through one of the exceptions in this proposed rule.</P>
                <P>3. Import or export of oceanic whitetip shark, or parts or products thereof, under an ESA section 10 permit or through the scientific research activity exception in this proposed rule.</P>
                <HD SOURCE="HD1">Public Comments Solicited</HD>
                <P>
                    We are soliciting comments, information, and/or recommendations on any aspect of this proposed rule from all concerned parties (see 
                    <E T="02">DATES</E>
                     and 
                    <E T="02">ADDRESSES</E>
                    ). We will consider all relevant information, comments, and recommendations received before reaching a final decision on ESA section 4(d) regulations for the oceanic whitetip shark. We may add or remove prohibitions or exceptions on the basis of public comment and in light of the biological status, conservation needs, and threats to the species.
                </P>
                <HD SOURCE="HD1">Public Hearing</HD>
                <P>
                    The ESA provides for a public hearing on this proposal, if requested. Requests must be filed by the date specified in the 
                    <E T="02">DATES</E>
                     section above.
                </P>
                <HD SOURCE="HD1">Peer Review</HD>
                <P>
                    In December 2004, the Office of Management and Budget issued a Final Information Quality Bulletin for Peer Review (Peer Review Bulletin), establishing minimum peer review standards, a transparent process for public disclosure, and opportunities for public input. The Peer Review Bulletin, implemented under the Information Quality Act (Pub. L. 106-554), is intended to provide public oversight on the quality of agency information, analyses, and regulatory activities. The text of the Peer Review Bulletin was published in the 
                    <E T="04">Federal Register</E>
                     on January 14, 2005 (70 FR 2664). The Peer Review Bulletin requires Federal agencies to subject “influential” scientific information to peer review prior to public dissemination. Influential scientific information is defined as “information the agency reasonably can determine will have or does have a clear and substantial impact on important public policies or private sector decisions,” and the Peer Review Bulletin provides agencies broad discretion in determining the appropriate process and level of peer review. The Peer Review Bulletin establishes stricter standards for the peer review of “highly influential” scientific assessments, defined as information whose “dissemination could have a potential impact of more than $500 million in any one year on either the public or private sector or that the dissemination is novel, controversial, or precedent-setting, or has significant interagency interest.” As stated previously, in developing this rule, we relied on previous NMFS reviews of this species, and thus we do not consider the scientific information underlying the proposed protective regulations to constitute newly compiled or disseminated influential scientific information requiring peer review per the Peer Review Bulletin.
                </P>
                <HD SOURCE="HD1">References</HD>
                <P>
                    A complete list of the references used in this proposed rule is available online (see 
                    <E T="02">ADDRESSES</E>
                    ) and upon request (see 
                    <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                    ).
                </P>
                <HD SOURCE="HD1">Classification</HD>
                <HD SOURCE="HD2">National Environmental Policy Act (NEPA)</HD>
                <P>
                    In the case of a species listed as threatened, section 4(d) of the ESA directs that the Secretary of Commerce (Secretary) shall issue such regulations as the Secretary deems necessary and advisable to provide for the conservation of the species. The Secretary may, by regulation, prohibit, with respect to any threatened species of fish or wildlife, any or all acts prohibited under section 9(a)(1). Accordingly, the promulgation of ESA section 4(d) protective regulations is subject to the requirements of NEPA, and we have prepared a draft EA analyzing the proposed 4(d) regulations and alternatives. We are seeking comment on the draft EA, which is available on the Federal eRulemaking Portal website (
                    <E T="03">https://www.regulations.gov</E>
                    ) or upon request (see 
                    <E T="02">DATES</E>
                     and 
                    <E T="02">ADDRESSES</E>
                    , above).
                </P>
                <HD SOURCE="HD2">Executive Order (E.O.) 12866 and 14094—Regulatory Planning and Review</HD>
                <P>This proposed rule has been determined to be not significant for the purposes of E.O. 12866, as amended by E.O. 14094.</P>
                <HD SOURCE="HD2">Regulatory Flexibility Act</HD>
                <P>
                    We prepared an initial regulatory impact analysis (IRFA) in accordance with section 603 of the Regulatory Flexibility Act (RFA) (5 U.S.C. 601, 
                    <E T="03">et seq.</E>
                    ). The IRFA analyzes the impacts to small entities that may be affected by the proposed rule. To review the IRFA, see the 
                    <E T="02">ADDRESSES</E>
                     section above. We welcome comments on this IRFA, which is summarized below.
                </P>
                <P>
                    The IRFA first identified the types and approximate number of small entities that would be subject to regulation under the proposed rule. It then evaluated the potential for the proposed rule to incrementally impact small entities, 
                    <E T="03">i.e.,</E>
                     result in impacts to small entities beyond those that would be incurred due to existing regulations but absent the proposed rule. The IRFA anticipates that regulations under the proposed rule would apply to thousands of small entities, but that only a small subset of these small entities would be impacted and impacts would be negligible. It is unlikely that the proposed rule would affect any small governmental jurisdictions. The small entities potentially impacted by the proposed rule are comprised of small businesses participating in numerous fisheries in the Atlantic Ocean, Eastern Pacific Ocean (EPO), and Western and Central Pacific Ocean (WCPO) management units, as well as small businesses involved in the commercial trade or transport of oceanic whitetip sharks or their derivative products. Any additional costs associated with enforcement of the rule would be incurred by government agencies that do not qualify as small entities.
                </P>
                <P>The proposed rule would prohibit the take, whether intentional or incidental, of oceanic whitetip sharks within waters of the United States or the territorial seas of the United States, as well as upon the high seas, by any person subject to the jurisdiction of the United States. Hundreds of small entities participating in commercial and recreational fisheries in the Atlantic Ocean, EPO, and WCPO Management Units (MUs) would be subject to prohibitions under the proposed regulations. These entities are categorized under North American Industry Classification System (NAICS) codes 114111 (commercial finfish fishing) and 487210 (scenic and sightseeing transportation (water)). For purposes of compliance with the RFA, NMFS has established a small business size standard of $11 million in annual gross receipts for all businesses in the commercial fishing industry.</P>
                <P>
                    Oceanic whitetip sharks in international waters of the Atlantic Ocean, EPO, and WCPO MUs are managed by the International Commission for the Conservation of Atlantic Tunas, the Inter-American Tropical Tuna Commission, and the 
                    <PRTPAGE P="41921"/>
                    Western and Central Pacific Fisheries Commission. There are approximately 2,100 U.S.-flagged vessels participating in international fisheries under the management of these Regional Fishery Management Organizations (RFMOs). Binding measures of each of the three RFMOs prohibit the retention, transshipping, landing, storing, selling, or offering for sale any part or whole carcass of oceanic whitetip sharks in any fishery by Contracting Parties, including U.S.-flagged vessels and persons subject to the jurisdiction of the United States. In addition, the Atlantic Highly Migratory Species (HMS) Pelagic Longline Fishery and Hawaii Pelagic Shallow Set Longline Fishery already undergo section 7 consultation on effects of the fisheries' actions on oceanic whitetip sharks in waters of the U.S. Exclusive Economic Zone and on the high seas. Despite the current lack of a 4(d) prohibition on take, NMFS included in biological opinions on each of the fisheries incidental take statements (ITSs) and RPMs intended to improve release conditions and post-release survival, as well as monitoring/reporting requirements for oceanic whitetip sharks. Given these baseline measures, the proposed rule is unlikely to impose additional reporting requirements on these fisheries for incidental take of oceanic whitetip sharks or result in any measurable incremental impacts to small entities due to their participation in international fisheries.
                </P>
                <P>Impacts of the proposed rule on U.S. federally and state-managed fisheries would be minor. Oceanic whitetip sharks are not a targeted species in U.S. fisheries due to a combination of factors, and historical landings of the sharks in state and federal waters have been very low. Possession and landing of sharks is prohibited in multiple fisheries, as well as in state waters of several coastal and island states and U.S. territories. Oceanic whitetip sharks are generally found outside state water boundaries, making catch of the sharks in state waters rare even if landing is not prohibited. Since 2000, the highest reported single-year total for combined commercial and recreational landings of oceanic whitetip sharks in all state and federal waters was 26 pounds in 2002. NOAA Fisheries' annual landings statistics indicate that there were no commercial or recreational landings of oceanic whitetip sharks in U.S. state or federal waters from 2015 to 2020, and there have been no commercial landings in U.S. territorial waters since 2016.</P>
                <P>Federally managed fisheries in the Atlantic most likely to interact with oceanic whitetip sharks and, therefore, most likely to be impacted by the proposed rule, include the Atlantic HMS fisheries and NMFS' Southeast Region's Coastal Migratory Pelagic (CMP) and Caribbean Reef Fish Fisheries. NMFS considers all HMS, CMP, and Caribbean Reef Fish fishery permit holders to be small entities because they had average annual receipts of less than $11 million for commercial fishing in 2021 and the proposed rule would apply to all permit holders in these fisheries. However, this proposed rule is not expected to incrementally impact permit holders in these fisheries in cases in which retention of oceanic whitetip sharks is already prohibited.</P>
                <P>Recent Atlantic HMS fishery management measures prohibit the retention of oceanic whitetip sharks in all commercial and recreational HMS fisheries (89 FR 278, January 3, 2024). As of October 2022, approximately 206 Shark Directed Limited Access and 241 Shark Incidental Limited Access permits were issued. From 2017 through 2021, no oceanic whitetip sharks were landed in HMS commercial fisheries in U.S. waters of the Atlantic Ocean, including the Gulf of Mexico and Caribbean Sea. During that same time period, two oceanic whitetip sharks were harvested in the recreational sector. Thus, while this proposed rule could directly impact small entities with HMS Shark Directed Limited Access permits and Shark Incidental Limited Access permits, these impacts are expected to be none to negligible as these permit holders cannot retain any oceanic whitetip sharks under the current regulations. Similarly, any impacts of this proposed rule on small entities sponsoring HMS tournaments in which recreational permit holders participate and on HMS charter/headboat operators are also expected to be none to negligible, given the prohibition on retention that is currently in place.</P>
                <P>The CMP Fishery, as managed by the Fishery Management Plan for CMP Resources in the Gulf of Mexico and Atlantic Region, has been identified as a fishery likely to interact with oceanic whitetip sharks. Oceanic whitetip sharks are not targeted and are only caught as bycatch. The Caribbean Reef Fish Fisheries are managed by the island-based fishery management plans (St. Croix, Puerto Rico, and St. Thomas/St. John). These island-based fisheries do not target oceanic whitetip sharks, although interactions can occur as bycatch. Based on historical data, the number of interactions in the CMP Fishery and the Caribbean Reef Fish Fisheries is expected to be small and, thus, any economic impacts resulting from the proposed rule would be minimal.</P>
                <P>In the EPO, oceanic whitetip sharks are not a managed species under the Pacific Fishery Management Council or the North Pacific Fishery Management Council, nor are they an expressly prohibited species given their low frequency of occurrence in the regions. Encounters with oceanic whitetip sharks are extremely rare in EPO federally managed waters, and NMFS does not anticipate any impacts to small entities participating in EPO federally managed fisheries from the proposed rule.</P>
                <P>In the WCPO, NMFS has completed section 7 consultations on all of its federally managed fisheries that are likely to incidentally capture oceanic whitetip sharks. This proposed rule would apply to participants in these WCPO fisheries, which include the Hawaii Deep-set Longline Fishery; the Hawaii Shallow-set Longline Fishery, the Hawaii, Guam, and CNMI Bottomfish Fisheries; and the United States WCPO Purse Seine Fishery. NMFS considers all participants in these fisheries to be small entities because they had average annual receipts of less than $11 million for commercial fishing in 2021. Despite the lack of a prohibition on take at the time, in each of the biological opinions on these fisheries, NMFS included ITSs and RPMs requiring monitoring/reporting of oceanic whitetip sharks as well as measures to minimize captures and improve release conditions and post-release survival. NMFS does not foresee any additional impacts to small entities participating in WCPO federally managed fisheries, and therefore does not foresee the need for additional consultation from the proposed rule.</P>
                <P>
                    This proposed rule would directly regulate small entities engaged in the import and export of oceanic whitetip sharks (or their derivative products) to or from the United States; the possession, transport, and sale of sharks that were illegally taken; and the possession, transport, and sale of oceanic whitetip sharks through both interstate and foreign commerce. Small entities subject to these prohibitions are largely categorized under NAICS codes 424460 (Fish and Seafood Merchant Wholesalers), 484 (Truck Transportation subsector), and 481112 (Scheduled Freight Air Transportation). According to data gathered from the Dun &amp; Bradstreet Hoovers Database, there are more than 8,000 U.S. small businesses with primary NAICS code 424460, approximately 500,000 U.S. small businesses with a primary NAICS code 
                    <PRTPAGE P="41922"/>
                    within the 484 subsector, and approximately 900 U.S. small businesses with primary NAICS code 481112. Despite the large number of small entities to which these prohibitions would apply, incremental impacts of this proposed rule on these small entities would likely be negligible. A query of the CITES trade database revealed a single import of oceanic whitetip shark fins into the United States between 2013 and 2021, and this import, which occurred in 2019, was seized or confiscated. The CITES data further indicate that no commercial exports of oceanic whitetip shark fins or specimens from the United States occurred between 2013 and 2021, and that the last export of oceanic whitetip sharks or derivative products for non-commercial purposes occurred in 2019. Import and export of oceanic whitetip sharks for scientific research purposes would not be impacted due to the proposed exception from the section 9(a)(1)(A) prohibitions on import and/or export when specific conditions are met. As noted above, existing regulations limit opportunities for legal harvest of oceanic whitetip sharks in U.S. fisheries, and very little such harvest has occurred in recent years. Thus, this proposed rule would have little or no incremental impact on legal U.S. trade of oceanic whitetip sharks, their fins, and other derivative products. Specifically, the proposed rule would have negligible impacts on U.S. small entities engaged in the import, export, wholesale, retail sale, or transport of fish and seafood products. This includes small entities with fishery-specific dealer permits for sharks.
                </P>
                <P>Potential impacts of this proposed rule on small entities beyond those related to fisheries and trade are anticipated to be minor. Under the exception to the section 9(a)(1)(A), (B), and (C) prohibitions for scientific research activities that meet certain conditions, entities conducting qualifying scientific research and/or enhancement activities would not need to obtain a section 10(a)(1)(A) scientific enhancement permit. Small entities conducting aquaculture activities resulting in incidental take of oceanic whitetip sharks could be required to obtain a section 10(a)(1)(B) incidental take permit. However, there is no foreseeable instance of this occurring, and it is possible that section 7 consultation on effects of the aquaculture operations on oceanic whitetip sharks would already address incidental take of the species if that did occur. Section 10 incidental take permits could also be required for entities conducting derelict gear or trash removal activities on the high seas or for those working to disentangle marine mammals from fishing gear/lines. However, these activities are typically carried out by federal and state agencies, which do not qualify as small entities.</P>
                <P>It has been determined that this proposed action would not duplicate or conflict with any federal rules. We note that fishermen, dealers, and managers in the fisheries to which this proposed rule would apply already must comply with domestic laws that implement a number of existing international agreements and other fishery management, environmental, and administrative measures. These include, but are not limited to, the Magnuson-Stevens Fishery and Conservation Management Act, the High Seas Fishing Compliance Act, the Marine Mammal Protection Act, the ESA, the National Environmental Policy Act, the Paperwork Reduction Act, the Coastal Zone Management Act, and the Shark Fin Sales Elimination Act.</P>
                <P>The RFA requires consideration of any significant alternatives to the proposed rule that would accomplish the stated objectives of the applicable statutes and would minimize significant economic impacts to small entities. We considered the following alternatives when developing this proposed rule.</P>
                <P>
                    <E T="03">Alternative 1: No-action Alternative.</E>
                     Under the No-action Alternative, NMFS would not establish an ESA 4(d) rule (
                    <E T="03">i.e.,</E>
                     no change from current management policies). The No-action Alternative represents the regulatory status quo. Under the No-action Alternative, none of the prohibitions under section 9(a)(1) of the ESA would be extended to provide for the conservation of the oceanic whitetip shark. Current programs would continue to guide management of the species. ESA section 7 consultations on federal agency actions would only address whether an action jeopardizes the continued existence of the oceanic whitetip shark. Reasonable and prudent alternatives would only be imposed if federal agency actions that take oceanic whitetip sharks are likely to jeopardize the continued existence of the species. ESA section 10 permits would not be required for non-federal actions that take the species because take would not be prohibited.
                </P>
                <P>Currently, a suite of region-specific rules and best practices (described above and detailed in the Draft Recovery Status Review (NMFS 2023)) regulate the harvest of oceanic shark species, including the oceanic whitetip shark, both in U.S. and international waters. NMFS concluded in its final listing determinations that existing regulations have not totally abated the impact of stressors on the threatened oceanic whitetip shark (83 FR 4153, January 30, 2018). In the Draft Recovery Status Review, NMFS finds that efforts to address overutilization of the species through regulatory measures appear largely inadequate (NMFS 2023). Under the No-action Alternative, oceanic whitetip sharks would remain vulnerable to stressors that would continue to affect population status of the species. Thus, the No-action Alternative is not necessarily a “no cost” alternative.</P>
                <P>
                    <E T="03">Alternative 2: Application of All ESA Section 9(a) Prohibitions with Exceptions (Proposed Alternative).</E>
                     Under the Proposed Alternative, ESA section 9(a)(1) prohibitions would apply to thousands of small entities engaged in commercial and recreational fishing; import, export, and wholesale of seafood products; and air and truck freight transport. However, as discussed above, both direct and indirect impacts to all potentially affected industries and entities would likely be minor. Import and export of oceanic whitetip sharks for qualifying scientific research purposes would not be impacted due to the proposed exception to the section 9(a)(1)(A) prohibition under this alternative. Alternative 2 was selected as the Proposed Alternative because it would promote the survival and recovery of the oceanic whitetip shark, and because this alternative would reduce the economic impacts on entities as compared to the economic impacts of Alternative 3.
                </P>
                <P>
                    <E T="03">Alternative 3: Application of ESA Section 9(a)(1) Prohibitions (Full Action Alternative).</E>
                     Alternative 3 would apply all Section 9(a)(1) prohibitions of the ESA to the oceanic whitetip shark, without exception. Potential impacts on small entities under this alternative would be equivalent to those generated under the Proposed Alternative, with a few notable exceptions. Under this alternative, an entity carrying out scientific research activities that would qualify for the exception to section 9(a)(1)(A) and (B) prohibitions under the Proposed Alternative would be required to obtain a section 10(a)(1)(A) permit for such activities. An entity that would qualify under the Proposed Alternative for the exception from the section 9(a)(1)(A) prohibitions on import and/or export of oceanic whitetip sharks or their parts would also be required to obtain a section 10(a)(1)(A) permit. Finally, under this alternative, a law enforcement official or management authority whose take of an oceanic whitetip shark would qualify under the 
                    <PRTPAGE P="41923"/>
                    Proposed Alternative for the exception from the prohibition on take would be required to obtain a section 10(a)(1)(A) permit. The administrative effort and associated cost of obtaining a section 10(a)(1)(A) permit that would not be required under the Proposed Action constitutes an incremental impact of Alternative 3, relative to impacts resulting from the Proposed Action. While activities that are known to contribute to the extinction risk of the species (
                    <E T="03">e.g.,</E>
                     take) would be prohibited under this alternative, activities that contribute to the conservation and recovery of the species would likely be deterred or delayed.
                </P>
                <HD SOURCE="HD2">E.O. 12988—Civil Justice Reform</HD>
                <P>We have determined that this proposed rule does not unduly burden the judicial system and that it meets the requirements of sections 3(a) and 3(b)(2) of E.O. 12988. We are proposing protective regulations pursuant to provisions in the ESA using an existing approach that improves the clarity of the regulations and minimizes the regulatory burden of managing ESA listings while retaining the necessary and advisable protections to provide for the conservation of threatened species.</P>
                <HD SOURCE="HD2">E.O. 13175—Consultation and Coordination With Indian Tribal Governments</HD>
                <P>The longstanding and distinctive relationship between the Federal and tribal governments is defined by treaties, statutes, executive orders, judicial decisions, and agreements, which differentiate tribal governments from the other entities that deal with, or are affected by, the Federal Government. This relationship has given rise to a special Federal trust responsibility involving the legal responsibilities and obligations of the United States toward Indian Tribes and with respect to Indian lands, tribal trust resources, and the exercise of tribal rights. Pursuant to these authorities, lands have been retained by Indian Tribes or have been set aside for tribal use. These lands are managed by Indian Tribes in accordance with tribal goals and objectives within the framework of applicable treaties and laws. E.O. 13175 outlines the responsibilities of the Federal Government in matters affecting tribal interests.</P>
                <P>E.O. 13175 requires that if NMFS issues a regulation that has substantial direct effects on the communities of Indian tribal governments and imposes substantial direct compliance costs on those communities, NMFS must consult with those governments, or the Federal Government must provide the funds necessary to pay the direct compliance costs incurred by the tribal governments. In developing this proposed rule, we found that the proposed 4(d) rule will not impose substantial direct compliance costs on the communities of Indian tribal governments and does not have tribal implications.</P>
                <HD SOURCE="HD2">E.O. 13132—Federalism</HD>
                <P>E.O. 13132 requires agencies to take into account any federalism impacts of regulations under development. It includes specific consultation directives for situations where a regulation will preempt state law or impose substantial direct compliance costs on state and local governments (unless required by statute). Neither of those circumstances is applicable to this proposed rule.</P>
                <HD SOURCE="HD2">Paperwork Reduction Act (PRA)</HD>
                <P>This proposed rule does not contain any new or revised collection of information requirements. This rule, if adopted, would not impose recordkeeping or reporting requirements on state or local governments, individuals, businesses, or organizations.</P>
                <HD SOURCE="HD2">E.O. 13211—Energy Supply, Distribution, or Use</HD>
                <P>E.O. 13211 requires agencies to prepare Statements of Energy Effects when undertaking “significant energy actions.” According to E.O. 13211, “significant energy action” means any action by an agency that promulgates or is expected to lead to the promulgation of a final rule or regulation that is a significant regulatory action under E.O. 12866 and is likely to have a significant adverse effect on the supply, distribution, or use of energy. NMFS has determined that no Statement of Energy Effects is required because this proposed rule is not significant under E.O. 12866.</P>
                <HD SOURCE="HD2">E.O. 12898—Environmental Justice</HD>
                <P>E.O. 12898 requires that Federal actions address environmental justice in the decision-making process. In particular, the adverse human health or environmental effects of the actions should not have a disproportionately high effect on minority and low-income communities. The proposed protective regulations are not expected to have a disproportionately high effect on minority populations or low-income populations.</P>
                <AUTH>
                    <HD SOURCE="HED">Authority: </HD>
                    <P>
                        The authority for this action is the Endangered Species Act of 1973, as amended (16 U.S.C. 1531 
                        <E T="03">et seq.</E>
                        ).
                    </P>
                </AUTH>
                <SIG>
                    <DATED>Dated: May 8, 2024.</DATED>
                    <NAME>Samuel D. Rauch, III,</NAME>
                    <TITLE>Deputy Assistant Administrator for Regulatory Programs, National Marine Fisheries Service.</TITLE>
                </SIG>
                <P>For the reasons set out in the preamble, NMFS proposes to amend 50 CFR part 223 as follows:</P>
                <PART>
                    <HD SOURCE="HED">PART 223—THREATENED MARINE AND ANADROMOUS SPECIES</HD>
                </PART>
                <AMDPAR>1. The authority citation for part 223 continues to read as follows:</AMDPAR>
                <AUTH>
                    <HD SOURCE="HED">Authority: </HD>
                    <P>
                        16 U.S.C. 1531-1543; subpart B, § 223.201-202 also issued under 16 U.S.C. 1361 
                        <E T="03">et seq.;</E>
                         16 U.S.C. 5503(d) for § 223.206(d)(9).
                    </P>
                </AUTH>
                <AMDPAR>2. Add § 223.216 to subpart B to read as follows:</AMDPAR>
                <SECTION>
                    <SECTNO>§ 223.216</SECTNO>
                    <SUBJECT>Oceanic whitetip shark.</SUBJECT>
                    <P>
                        (a) 
                        <E T="03">Prohibitions.</E>
                         The prohibitions of section 9(a)(1) of the ESA (16 U.S.C. 1538(a)(1)) relating to endangered species apply to the threatened oceanic whitetip shark listed in § 223.102(e), except as provided in paragraph (b) of this section.
                    </P>
                    <P>
                        (b) 
                        <E T="03">Exceptions.</E>
                         Exceptions to the prohibitions applied in paragraph (a) of this section to the threatened oceanic whitetip shark listed in § 223.102(e) are described in paragraphs (b)(1) through (b)(3) of this section.
                    </P>
                    <P>
                        (1) 
                        <E T="03">Scientific research import/export exception.</E>
                         The prohibitions of section 9(a)(1)(A) of the ESA, as applied in paragraph (a) of this section, relating to the threatened oceanic whitetip shark listed in § 223.102(e) do not apply when the following conditions are met: (1) the import or export is accompanied by proper permits issued under the Convention on International Trade in Endangered Species of Wild Fauna and Flora (CITES) indicating that the trade is for the purposes of scientific research; and (2) the import or export is carried out in accordance with all other applicable laws and regulations. If these conditions are met, import and/or export for the purposes of scientific research would not constitute a violation of the section 9(a)(1)(A) prohibitions, and an ESA section 10(a)(1)(A) permit would not be required.
                    </P>
                    <P>
                        (2) 
                        <E T="03">Scientific research take exception.</E>
                         The take prohibitions of sections 9(a)(1)(B) and (C) of the ESA, as applied in paragraph (a) of this section, relating to the threatened oceanic whitetip shark listed in § 223.102(e) do not apply to ongoing or future scientific research when the following conditions are met: (1) the scientific research activities are carried out by or in collaboration with a research institution; state, tribal, or 
                        <PRTPAGE P="41924"/>
                        federal agency; or other scientific organization in a good faith effort to advance the conservation and/or recovery of the species; (2) the scientific research activities are intended to involve only non-lethal take, 
                        <E T="03">i.e.,</E>
                         no individuals may be intentionally killed for the purposes of scientific research under this exception; and (3) the scientific research activities are carried out in accordance with all other applicable laws and regulations. If these conditions are met, scientific research activities resulting in take would not constitute a violation of the prohibitions, and an ESA section 10(a)(1)(A) permit would not be required.
                    </P>
                    <P>
                        (3) 
                        <E T="03">Law enforcement take exception.</E>
                         The take prohibitions of section 9(a)(1)(B) of the ESA, as applied in paragraph (a) of this section, relating to the threatened oceanic whitetip shark listed in § 223.102(e) do not apply to law enforcement officials or management authorities, including any employee or designee of NMFS or of any other governmental entity that has co-management authority for the oceanic whitetip shark if, when acting in the course of their official duties, it is necessary to take an oceanic whitetip shark to: aid a sick, injured, entangled, or stranded oceanic whitetip shark, dispose of a dead oceanic whitetip shark, or salvage a dead oceanic whitetip shark (or parts or samples thereof) which may be useful for scientific study.
                    </P>
                </SECTION>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10466 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3510-22-P</BILCOD>
        </PRORULE>
    </PRORULES>
    <VOL>89</VOL>
    <NO>94</NO>
    <DATE>Tuesday, May 14, 2024</DATE>
    <UNITNAME>Notices</UNITNAME>
    <NOTICES>
        <NOTICE>
            <PREAMB>
                <PRTPAGE P="41925"/>
                <AGENCY TYPE="F">DEPARTMENT OF AGRICULTURE</AGENCY>
                <SUBJECT>Notice of Information Collection, Request for Comment</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Department of Agriculture (USDA).</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice and request for comments.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Office of the Chief Information Officer, as part of its continuing effort to reduce paperwork and respondent burden, invites the public to comment on the “Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery” for approval under the Paperwork Reduction Act. This collection was developed as part of a Federal Government-wide effort to streamline the process for seeking feedback from the public on service delivery. This notice announces our intent to submit this collection to Office of Management and Budget (OMB) for approval and solicit comments on specific aspects for the proposed information collection.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Comments on this notice must be received by July 15, 2024 to be assured of consideration.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Interested persons are invited to submit comments on this notice. Comments may be submitted through the: Federal eRulemaking Portal: This website provides the ability to type short comments directly into the comment field on this web page or attach a file for lengthier comments. Go to 
                        <E T="03">http://www.regulations.gov.</E>
                         Follow the on-line instructions at that site for submitting comments.
                    </P>
                    <P>
                        You may also send comments to the Desk Officer for USDA, Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503. All items submitted must include the Agency name and docket number Department of Agriculture, USDA-2022-0011. Comments received in response to this docket will be made available for public inspection and posted without change, including any personal information, to 
                        <E T="03">http://www.regulations.gov.</E>
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Levi S. Harrell, email: 
                        <E T="03">Levi.Harrell@usda.gov;</E>
                         telephone: (202) 924-0168. Person with disabilities who require alternative means for communication should contact the USDA Target Center at (202) 720-2600 (voice) or 844-433-2774 (toll-free nationwide).
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P/>
                <P>
                    <E T="03">Title:</E>
                     Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery.
                </P>
                <P>
                    <E T="03">OMB Number:</E>
                     0503-0021.
                </P>
                <P>
                    <E T="03">OMB Expiration Date of Approval:</E>
                     Three years from the approval date.
                </P>
                <P>
                    <E T="03">Type of Request:</E>
                     Renewal/Extension of approval for a current information collection.
                </P>
                <P>
                    <E T="03">Abstract:</E>
                     The proposed information collection activity provides a means to garner qualitative customer and stakeholder feedback in an efficient, timely manner, in accordance with the Administration's commitment to improve service delivery. By qualitative feedback, we mean information that provides useful insights on perceptions and opinions, but not statistical surveys that yield quantitative results that can be generalized to the population. This feedback will, (1) provide insights into customer or stakeholder perceptions, experiences and expectations, (2) provide an early warning of issues with service and, (3) focus attention on areas where communication, training or changes in operations might improve delivery of products or services. This collection will allow for ongoing, collaborative and actionable communications between the Agency and its customers and stakeholders. It will also allow feedback to contribute directly to the improvement of program management.
                </P>
                <P>The solicitation of feedback will target areas such as: Timeliness, appropriateness, accuracy of information, courtesy, efficiency of service delivery, and resolution of issues with service delivery. Responses will be assessed to plan and inform efforts to improve or maintain the quality of service offered to the public. If this information is not collected, vital feedback from customers and stakeholders on the Agency's services will be unavailable.</P>
                <P>The Agency will only submit a collection for approval under this generic clearance if it meets the following conditions:</P>
                <P>• The collections are voluntary;</P>
                <P>• The collections are low-burden for respondents (based on considerations of total burden hours, total number of respondents, or burden-hours per respondent) and are low-cost for both the respondents and the Federal Government;</P>
                <P>• The collections are non-controversial and do not raise issues of concern to other Federal agencies;</P>
                <P>• Any collection is targeted to the solicitation of opinions from respondents who have experience with the program or may have experience with the program in the future;</P>
                <P>• Personally identifiable information (PII) is collected only to the extent necessary and is not retained;</P>
                <P>• Information gathered will be used only internally for general service improvement and program management purposes and is not intended for release outside of the agency;</P>
                <P>• Information gathered will not be used for substantially informing influential policy decisions; and</P>
                <P>• Information gathered will yield qualitative information; the collections will not be designed or expected to yield statistically reliable results or used as though the results are generalizable to the population of study.</P>
                <P>
                    Feedback collected under this generic clearance provides useful information, but it does not yield data that can be generalized to the overall population. This type of generic clearance for qualitative information will not be used for quantitative information collections that are designed to yield reliably actionable results, such as monitoring trends over time or documenting program performance. Such data usage requires more rigorous designs that address the target population to which generalizations will be made, the sampling frame, the sample design (including stratification and clustering), the precision requirements or power calculations that justify the proposed sample size, the expected response rate, methods for assessing potential non-response bias, the protocols for data collection, and any testing procedures that were or will be undertaken prior to fielding the study. Depending on the degree of influence the results are likely 
                    <PRTPAGE P="41926"/>
                    to have, such collections may still be eligible for submission for other generic mechanisms that are designed to yield quantitative results.
                </P>
                <P>As a general matter, information collections will not result in any new system of records containing privacy information and will not ask questions of a sensitive nature, such as sexual behavior and attitudes, religious beliefs, and other matters that are commonly considered private.</P>
                <P>
                    <E T="03">Current Actions:</E>
                     Renewal/Extension of approval for a current information collection.
                </P>
                <P>
                    <E T="03">Type of Review:</E>
                     Renewal.
                </P>
                <P>
                    <E T="03">Affected Public:</E>
                     Individuals and Households, Businesses and Organizations, State, Local or Tribal Government.
                </P>
                <P>
                    <E T="03">Estimated Number of Respondents:</E>
                     30,000.
                </P>
                <P>Below we provide projected average estimates for the next 3-years:</P>
                <P>
                    <E T="03">Average Expected Annual Number of Activities:</E>
                     20.
                </P>
                <P>
                    <E T="03">Average Number of Respondents per Activity:</E>
                     1.
                </P>
                <P>
                    <E T="03">Annual Responses:</E>
                     30,000.
                </P>
                <P>
                    <E T="03">Frequency of Response:</E>
                     Once per request.
                </P>
                <P>
                    <E T="03">Average Minutes per Response:</E>
                     30.
                </P>
                <P>
                    <E T="03">Burden Hours:</E>
                     16,750.
                </P>
                <P>
                    <E T="03">Request for Comments:</E>
                     Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval. Comments are invited on: (a) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology; and (e) estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services to provide information. Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, disclose, or provide information to or for a Federal agency. This includes the time needed to review instructions to (1) develop, acquire, install, and utilize technology and systems for the purpose of collecting, validating and verifying information, processing and maintaining information, and disclosing and providing information; (2) train personnel and be able to respond to a collection of information, to search data sources, (3) complete and review the collection of information; and to transmit or otherwise disclose the information.
                </P>
                <P>
                    All written comments will be available for public inspection at 
                    <E T="03">Regulations.gov</E>
                    .
                </P>
                <P>An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid Office of Management and Budget control number.</P>
                <SIG>
                    <NAME>Gary Washington,</NAME>
                    <TITLE>Chief Information Officer, Office of the Chief Information Officer.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10542 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3410-KR-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF AGRICULTURE</AGENCY>
                <SUBJECT>Notice of Request for Revision of a Currently Approved Information Collection; Digitized Advisory Committee and Research and Promotion Background Information Revised Supplemental Lists and Including Marketing in Collection</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Department of Agriculture.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice and request for comments.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This notice announces the U.S. Department of Agriculture's (USDA) intention to revise to the currently approved through December 31, 2025, Advisory Committee and Research and Promotion Background Information AD-755 and Supplemental Lists—Agricultural Marketing Service (AMS) Research and Promotion Commodity specific questionnaire and include a new Marketing specific questionnaire. The revised form and supplemental information will allow applicants to answer questions in more detail of their foreign citizenship identification (passport number, passport expiration date, and issuing country). In addition, if an applicant is a foreign national, identify if this person resided in the United States (U.S.) for 3 years or more continuous years. The primary objective is to determine the qualifications, suitability and availability of a candidates to serve on advisory committees and/or research and promotion boards. Lastly, the AD-755 Form and supplemental questionnaire are being digitized to allow applicants to access and complete the application form electronically.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Comments on this notice must be received by July 15, 2024 to be assured of consideration. Comments must be postmarked 10 business days prior to the deadline to ensure timely receipt.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>USDA invites interested persons to submit comments on this notice.</P>
                    <P>
                        <E T="03">Written Comments:</E>
                         Comments may be submitted through one of the following methods:
                    </P>
                    <P>
                        ☐ Mailed to the attention of Ms. Cikena Reid, Committee Management Officer, the White House Liaison Office, 1400 Independence Avenue SW, the Whitten Building, Room 542-A, Washington, DC 20250; fax: 202-720-9286; or by email: 
                        <E T="03">cikena.reid@usda.gov.</E>
                    </P>
                    <P>
                        ☐ 
                        <E T="03">Federal eRulemaking Portal:</E>
                         This website provides the ability to type short comments directly into the comment field on this web page or attach a file for lengthier comments. Go to 
                        <E T="03">http://www.regulations.gov.</E>
                         Follow the on-line instructions at that site for submitting comments.
                    </P>
                    <P>
                        ☐ 
                        <E T="03">Hand- or courier-delivered submittals:</E>
                         Deliver to White House Liaison Office, U.S. Department of Agriculture, 1400 Independence Avenue SW, the Whitten Building, Room 542-A, Washington, DC 20250-3700.
                    </P>
                    <P>
                        <E T="03">Instructions:</E>
                         All items submitted by mail or electronic mail must include the Agency name and docket number. Comments received in response to this notice will be made available for public inspection and posted without change, including any personal information, to 
                        <E T="03">http://www.regulations.gov.</E>
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Contact Cikena Reid, USDA Committee Management Officer, Office of the Secretary, U.S. Department of Agriculture, 1400 Independence Ave. SW, the Whitten Building, Room 542-A, Washington, DC 20250; office phone: 202-720-2406; email: 
                        <E T="03">cikena.reid@usda.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 35), this notice announces the U.S. Department of Agriculture's (USDA) intention to request an extension for—and a revision to the Advisory Committee and Research and Promotion Background Information collection form and applicable supplemental questionnaires.</P>
                <P>
                    The revised form and supplemental information will allow applicants to answer questions in more detail of their foreign citizenship identification (passport number, passport expiration date, and issuing country). In addition, if an applicant is a foreign national, identify if this person resided in the United States (U.S.) for 3 years or more continuous years. The primary objective 
                    <PRTPAGE P="41927"/>
                    is to determine the qualifications, suitability, and availability of a candidates to serve on advisory committees, research and promotion boards, and now marketing boards. The primary objective is to determine the qualifications, suitability, and availability of a candidate to serve on advisory committees, research and promotion, and marketing boards. Lastly, the AD-755 Form and supplemental questionnaire are being digitized for the receipt of applications to allow applicants to access and complete the form electronically and more securely safeguard data and information collection.
                </P>
                <P>
                    <E T="03">Title:</E>
                     Advisory Committee and Research and Promotion Background Information.
                </P>
                <P>
                    <E T="03">OMB Number:</E>
                     0505-0001.
                </P>
                <P>
                    <E T="03">Expiration Date of Approval:</E>
                     December 31, 2025.
                </P>
                <P>
                    <E T="03">Type of Request:</E>
                     Revision of a currently approved information collection form document and with a revised research and promotion board supplemental list and add the marketing supplemental list with digitization to the receipt of applications.
                </P>
                <P>
                    <E T="03">Abstract:</E>
                     The primary objective is to determine the qualifications, suitability and availability of a candidate to serve on advisory committees and/or research and promotion boards. The information will be used to both conduct background clearances on the candidates and to compile annual reports regarding membership.
                </P>
                <P>
                    <E T="03">Estimate of Burden:</E>
                     Public reporting burden for this collection of information is estimated to average 30 minutes per response.
                </P>
                <P>
                    <E T="03">Respondents:</E>
                     Individuals.
                </P>
                <P>
                    <E T="03">Estimated Number of Respondents:</E>
                     5,500.
                </P>
                <P>
                    <E T="03">Estimated Number of Responses per Respondent:</E>
                     One (1).
                </P>
                <P>
                    <E T="03">Estimated Total Annual Burden on Respondents:</E>
                     5,500.
                </P>
                <P>Comments are invited on: (1) whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (2) the accuracy of the agency's estimate of the burden of the proposed collection of information including the validity of the methodology and assumptions used; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) ways to minimize the burden of the collection of information on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology.</P>
                <P>
                    Comments may be sent to Ms. Cikena Reid, Committee Management Officer, the White House Liaison Office, 1400 Independence Avenue SW, the Whitten Building, Room 536-A, Washington, DC 20250; fax: 202-720-9286; or by email: 
                    <E T="03">cikena.reid@usda.gov.</E>
                     Comments must be postmarked 10 business days prior to the deadline to ensure timely receipt.
                </P>
                <P>All comments received will be available for public inspection during regular business hours at the same address.</P>
                <P>All responses to this notice will be summarized and included in the request for OMB approval. All comments will become a matter of public record.</P>
                <SIG>
                    <DATED>Dated: May 8, 2024.</DATED>
                    <NAME>Cikena Reid,</NAME>
                    <TITLE>USDA Committee Management Officer.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10484 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3410-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF AGRICULTURE</AGENCY>
                <SUBJECT>Notice of Request for Extension or Renewal of a Currently Approved Information Collection</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Office of the Assistant Secretary for Civil Rights, U.S. Department of Agriculture.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice and request for comments.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>In accordance with the Paperwork Reduction Act of 1995, this notice announces the intention of the Office of the Assistant Secretary for Civil Rights (OASCR) to request a renewal to a currently approved information collection. OASCR will use the information collected to process Respondent's program discrimination complaints conducted or assisted by USDA.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Comments on this notice must be received by July 15, 2024 to be assured of consideration.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>The Office of the Assistant Secretary for Civil Rights invites interested persons to submit comments on this notice. Comments may be submitted by one of the following methods:</P>
                    <P>
                        <E T="03">Federal eRulemaking Portal:</E>
                         This website provides the ability to type short comments directly into the comment field on this web page or attach a file for lengthier comments. Go to 
                        <E T="03">http://www.regulations.gov.</E>
                         Follow the on-line instructions on the eRulemaking Portal submitting comments.
                    </P>
                    <P>
                        <E T="03">U.S. Mail, including CD-ROMs, etc.:</E>
                         Send to U.S. Department of Agriculture, Office of the Assistant Secretary for Civil Rights, 1400 Independence Avenue SW, Washington, DC 20250-9410.
                    </P>
                    <P>
                        <E T="03">Hand or courier-delivered submittals:</E>
                         Deliver to 1400 Independence Avenue, Washington, DC 20250-9410.
                    </P>
                    <P>
                        <E T="03">Instructions:</E>
                         All items submitted by U.S. mail or electronic mail must include the Agency name, Office of the Assistant Secretary for Civil Rights. Comments received in response to this docket will be made available for public inspection and posted without changes, including any personal information, to 
                        <E T="03">http://www.regulations.gov.</E>
                    </P>
                    <P>
                        <E T="03">Docket:</E>
                         For access to background documents or comments received, please contact the Office of the Assistant Secretary for Civil Rights at 1400 Independence Avenue SW, DC 20250, between 8:00 a.m. and 4:30 p.m., Monday through Friday.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Contact Winona Massie, Executive Director, Center for Civil Rights Operations, Office of the Assistant Secretary for Civil Rights, U.S. Department of Agriculture, 1400 Independence Avenue SW, Washington, DC 20250, (202) 720-3808.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 35), this notice announces the intention of the Office of the Assistant Secretary for Civil Rights to request approval for an existing collection in use without an Office of Management and Budget (OMB) control number.</P>
                <P>
                    <E T="03">Title:</E>
                     USDA Program Discrimination Complaint Form.
                </P>
                <P>
                    <E T="03">OMB Number:</E>
                     OMB No. 0508-0002.
                </P>
                <P>
                    <E T="03">Expiration Date of Approval:</E>
                     May 31, 2024.
                </P>
                <P>
                    <E T="03">Type of Request:</E>
                     Extension and renewal of a currently approved information collection.
                </P>
                <P>
                    <E T="03">Abstract:</E>
                     Under 7 CFR 15.6, “Any person who believes himself/herself or any specific class of individuals to be subjected to discrimination [in any USDA assisted program or activity] may by himself/herself or by an authorized representative file a written complaint.” Under 7 CFR 15d.5(a), “Any person who believes that he or she (or any specific class of individuals) has been, or is being, subjected to [discrimination in any USDA conducted program or activity] * * * may file [on his or her own,] (or file through an authorized representative) a written complaint alleging such discrimination.” The collection of this information is an avenue by which the individual or his representative may file such a program discrimination complaint.
                </P>
                <P>
                    The requested information, which can be submitted by filling out a form or by 
                    <PRTPAGE P="41928"/>
                    submitting a letter, is necessary for USDA OASCR to address the alleged discriminatory action. The Respondent is asked to state his/her name, mailing address, property address (if different from mailing address), telephone number, email address (if any) and to provide a name and contact information for the Respondent's representative (if any). A brief description of who was involved with the alleged discriminatory action, what occurred and when, is requested. In the event that the Respondent is filing the program discrimination complaint more than 180 days after the alleged discrimination occurred, the Respondent is asked to provide the reason for the delay.
                </P>
                <P>Finally, the Respondent is asked to identify which bases are alleged to have motivated the discriminatory action. The form explains that laws and regulations prohibit on the bases of race, color, national origin, age, sex, gender identity (including gender expression), disability, religion, sexual orientation, marital or familial status, or because all or part of the individual's income is derived from any public assistance program, but that not all bases apply to all programs.</P>
                <P>The program discrimination complaint filing information, which is voluntarily provided by the Respondent, will be used by the staff of USDA OASCR to intake, investigate, resolve, and/or adjudicate the Respondent's complaint. The program discrimination complaint form will enable OASCR to better collect information from complainants in a timely manner, therefore, reducing delays and errors in determining USDA jurisdiction.</P>
                <P>
                    <E T="03">Estimate of Burden:</E>
                     Public reporting burden for this collection of information is estimated to average 1 hour per response.
                </P>
                <P>
                    <E T="03">Respondents:</E>
                     Producers, applicants.
                </P>
                <P>
                    <E T="03">Estimated Number of Respondents:</E>
                     280.
                </P>
                <P>
                    <E T="03">Estimated Number of Responses per Respondent:</E>
                     1.
                </P>
                <P>
                    <E T="03">Estimated Total Annual Burden on Respondents:</E>
                     280 hours.
                </P>
                <P>Comments are invited on: (1) whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (2) the accuracy of the agency's estimate of the burden of the proposed collection of information including the validity of the methodology and assumptions used; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) ways to minimize the burden of the collection of information on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology. Comments may be sent by any of the following methods:</P>
                <P>
                    • 
                    <E T="03">Email:</E>
                     Send comments to: 
                    <E T="03">OASCR.CCRO@USDA.Gov.</E>
                </P>
                <P>
                    • 
                    <E T="03">U.S. Mail:</E>
                     Winona Massie, Executive Director, Center for Civil Rights Operations, Office of the Assistant Secretary for Civil Rights, U.S. Department of Agriculture, 1400 Independence Ave. SW, Washington, DC 20250-9410.
                </P>
                <P>All comments received will be available for public inspection during regular business hours at the same address.</P>
                <P>All responses to this notice will be summarized and included in the request for Office of Management and Budget approval. All comments will become a matter of public record.</P>
                <SIG>
                    <NAME>Penny Brown Reynolds,</NAME>
                    <TITLE>Deputy Assistant Secretary for Civil Rights, Office of the Assistant Secretary for Civil Rights.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10536 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3410-18-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF AGRICULTURE</AGENCY>
                <SUBAGY>Rural Housing Service</SUBAGY>
                <DEPDOC>[Docket No. RHS-24-CF-0014]</DEPDOC>
                <SUBJECT>Announcement of the Availability of Puerto Rico Rural Partners Network Rural Community Development Initiative</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Rural Housing Service, USDA.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of funding of availability (NOFA).</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Rural Housing Service (RHS or the Agency), a Rural Development (RD) agency of the United States Department of Agriculture (USDA), announces the acceptance of applications under the Puerto Rico Rural Partners Network (RPN) Rural Community Development Initiative (RCDI) program to provide authorized activities in Puerto Rico areas affected by a disaster declared by the President or the Secretary of Agriculture. These grants will be made to qualified intermediary organizations that will provide financial and technical assistance to recipients to develop their capacity and ability to undertake projects related to housing, community facilities, or community and economic development that will support the community. The maximum grant award amount available to an intermediary is $250,000. The Consolidated Security, Disaster Assistance, and Continuing Appropriations Act, 2009, created the Disaster Assistance Fund (DAF) and the Secretary of Agriculture has authorized $1,000,000 of DAF funds to be utilized in Puerto Rico for the RCDI program for the purposes described in this NOFA.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Completed applications must be submitted using one of the following methods:</P>
                    <P>
                        • 
                        <E T="03">Paper submissions:</E>
                         Paper applications must be received by 4:00 p.m. local time by the Puerto Rico Rural Development State Office July 3, 2024.
                    </P>
                    <P>
                        • 
                        <E T="03">Electronic submissions:</E>
                         Electronic applications must be submitted via 
                        <E T="03">Grants.gov</E>
                         by 11:59 p.m. Eastern Time on June 28, 2024.
                    </P>
                    <P>Prior to official submission of applications, applicants may request technical assistance or other application guidance from the Agency, as long as such requests are made prior to June 24, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Application information for electronic submissions may be found at 
                        <E T="03">https://www.Grants.gov/.</E>
                         Applicants may also request paper application packages from the Puerto Rico Rural Development State Office at (787) 766-5095.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Danna Quiles, Community Programs Director, Puerto Rico Rural Development State Office, United States Department of Agriculture, 654 Muñoz Rivera Ave., Suite 601, San Juan, Puerto Rico 00918, Phone: (787) 766-5346, Email: 
                        <E T="03">danna.quiles@usda.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">Overview</HD>
                <P>
                    <E T="03">Federal Awarding Agency Name:</E>
                     Rural Housing Service, (RHS).
                </P>
                <P>
                    <E T="03">Funding Opportunity Title:</E>
                     Puerto Rico RPN RCDI.
                </P>
                <P>
                    <E T="03">Announcement Type:</E>
                     Notice of Funding Availability (NOFA).
                </P>
                <P>
                    <E T="03">Funding Opportunity Number:</E>
                     USDA-RD-HCFP-PR-RPN-RCDI-2024.
                </P>
                <P>
                    <E T="03">Assistance Listing:</E>
                     10.446.
                </P>
                <P>
                    <E T="03">Dates:</E>
                     Applications must be submitted using one of the following methods:
                </P>
                <P>
                    • 
                    <E T="03">Paper submissions:</E>
                     The deadline for receipt of a paper application is 4 p.m. local time, to the Puerto Rico Rural Development State Office, 654 Muñoz Rivera Ave., Suite 601, San Juan, Puerto Rico 00918. July 3, 2024. Applicants intending to mail applications must provide sufficient time to permit delivery on or before the closing deadline date and time. Acceptance by the United States Postal Service or private mailer does not constitute delivery. Facsimile (FAX), electronic mail, and postage due applications will 
                    <PRTPAGE P="41929"/>
                    not be accepted. The application dates and times are firm. The Agency will not consider any application received after the deadline.
                </P>
                <P>
                    • 
                    <E T="03">Electronic submission:</E>
                     Electronic applications will be accepted via 
                    <E T="03">Grants.gov</E>
                    . The deadline for receipt of an electronic applications via 
                    <E T="03">Grants.gov</E>
                     is 11:59 p.m. Eastern Time on June 28, 2024. The application dates and times are firm. The Agency will not consider any application received after the deadline. The Agency recommends not filing electronic submissions too close to the submission deadline in the event there is a problem with the system. Applicants that choose to mail applications in lieu of an electronic submission must provide sufficient time to permit delivery on or before the closing deadline date and time. Acceptance by the United States Postal Service or private mailer does not constitute delivery. Facsimile (FAX), electronic mail and postage due applications will not be accepted. Prior to official submission of applications, applicants may request technical assistance or other application guidance from the Agency, as long as such requests are made prior to June 24, 2024. Technical assistance is not meant to be an analysis or assessment of the quality of the materials submitted, a substitute for agency review of completed applications, nor a determination of eligibility, if such determination requires in-depth analysis. The Agency will not accept any applications or consider additional information or documentation received after the application deadline. The application dates and times are firm. The Agency reserves the right to contact applicants to seek clarification information on materials contained in the submitted application.
                </P>
                <P>
                    <E T="03">Rural Development Key Priorities:</E>
                     The Agency encourages applicants to consider projects that will advance the following key priorities (more details available at 
                    <E T="03">https://www.rd.usda.gov/priority-points</E>
                    ):
                </P>
                <P>• Addressing Climate Change and Environmental Justice; Reducing climate pollution and increasing resilience to the impacts of climate change through economic support to rural communities.</P>
                <P>• Advancing Racial Justice, Place-Based Equity, and Opportunity; Ensuring all rural residents have equitable access to RD programs and benefits from RD funded projects.</P>
                <P>• Creating More and Better Market Opportunities; Assisting rural communities recover economically through more and better market opportunities and through improved infrastructure.</P>
                <P>
                    For further information, visit 
                    <E T="03">https://www.rd.usda.gov/priority-points.</E>
                </P>
                <HD SOURCE="HD1">A. Program Description</HD>
                <P>
                    1. 
                    <E T="03">Purpose of the Program.</E>
                </P>
                <P>
                    The program is designed to assist qualified private organizations, nonprofit organizations, and public (including tribal) intermediary organizations located in Puerto Rico, proposing to carry out financial and technical assistance programs to improve housing, community facilities, and community and economic development projects in rural areas of Puerto Rico where a Presidential declaration of a major disaster was made under the Robert T. Stafford Disaster Relief and Emergency Assistance Act (42 U.S.C 5121 
                    <E T="03">et seq.</E>
                    ) (Stafford Act). This program requires the intermediary (Grantee) to provide a program of financial and technical assistance to recipients. The recipients will, in turn, provide programs to their communities (beneficiaries).
                </P>
                <P>Awards made under this NOFA will help rural communities and nonprofits to build capacity and technical assistance for readiness for more competitive funding applications and successful project completion. The aim is to support rural communities and nonprofit organizations in Puerto Rico's Rural Partners Community Networks to access federal funding to address community and economic challenges in areas where a Presidential declaration of a major disaster was issued.</P>
                <P>
                    2. 
                    <E T="03">Statutory and Regulatory Authority.</E>
                </P>
                <P>Congress created the RCDI program in 1999 (Pub. L. 106-78), and The Consolidated Security, Disaster Assistance, and Continuing Appropriations Act, 2009, Public Law 110-329 (7 U.S.C. 6945) (“the Act”), created the Disaster Assistance Fund (DAF). The Act authorized additional amounts for authorized activities in areas affected by a disaster declared by the President or the Secretary of Agriculture. This program is implemented under the guidelines announced in this Notice and 2 CFR part 200.</P>
                <P>
                    3. 
                    <E T="03">Definitions.</E>
                </P>
                <P>
                    <E T="03">Agency</E>
                    —The Rural Housing Service or its successor.
                </P>
                <P>
                    <E T="03">Beneficiary</E>
                    —Entities or individuals that receive benefits from assistance provided by the Recipient.
                </P>
                <P>
                    <E T="03">Capacity</E>
                    —The ability of a Recipient to implement housing, community facilities, or community and economic development projects.
                </P>
                <P>
                    <E T="03">Conflict of interest</E>
                    —A situation in which a person or entity has competing personal, professional, or financial interests that make it difficult for the person or business to act impartially. Regarding use of grant funds, federal procurement standards prohibit transactions that involve a real or apparent conflict of interest for owners, employees, officers, agents, or their immediate family members having a financial or other interest in the outcome of the project; or that restrict open and free competition for unrestrained trade. Specifically, project funds may not be used for services or goods going to, or coming from, a person or entity with a real or apparent conflict of interest, including, but not limited to, owner(s) and their immediate family members. An example of a conflict of interest occurs when an employee of the grantee, a member of the grantee's board of directors, or the immediate family of either, has the appearance of a professional or personal financial interest in a recipient receiving the benefits or services of the grant.
                </P>
                <P>
                    <E T="03">Federally recognized Tribes</E>
                    —Tribal entities recognized and eligible for funding and services from the Bureau of Indian Affairs, based on the most recent notice in the 
                    <E T="04">Federal Register</E>
                     published by the Bureau of Indian Affairs (pursuant to Pub. L. 103-454) and Tribes that received federal recognition after the most recent publication. Tribally designated housing entities (TDHE) are eligible RCDI recipients. There are no federally recognized tribes nor TDHEs in Puerto Rico.
                </P>
                <P>
                    <E T="03">Financial assistance</E>
                    —Funds, not to exceed $10,000 per award, used by the intermediary to purchase supplies and equipment to build the recipient's capacity.
                </P>
                <P>
                    <E T="03">Funds</E>
                    —The Puerto Rico RPN RCDI grant funds that have been provided by the Grantee.
                </P>
                <P>
                    <E T="03">Intermediary</E>
                    —A qualified private organization, nonprofit organization (including faith-based and community organizations and philanthropic organizations), or public (including tribal) organization, located in Puerto Rico, that provides financial and technical assistance to multiple recipients.
                </P>
                <P>
                    <E T="03">Low-income rural community</E>
                    —An authority, district, economic development authority, regional council, federally recognized Tribe, or unit of government representing an incorporated city, town, village, county, township, parish, Indian reservation or borough whose income is at or below 80 percent of either (i) the state median household income of $21,967 or (ii) national Median Household Income of $69,021, whichever is higher, as measured by the 2020 Census.
                    <PRTPAGE P="41930"/>
                </P>
                <P>
                    <E T="03">Recipient</E>
                    —The entity that receives the financial and technical assistance from the intermediary. The recipient must be a nonprofit community-based housing and community development organization, low-income rural community, municipality, or a federally recognized tribe, within the selected (15) communities in the geographical area of the Puerto Rico RPN (see Appendix A). There are no federally recognized tribes nor TDHEs in Puerto Rico.
                </P>
                <P>
                    <E T="03">Rural and rural area</E>
                    —All Census Designated Places (CDP) in Puerto Rico with populations of 50,000 or less. Under this new methodology, all CDPs whose populations exceed 50,000 are not rural; however, individual census tracts within those CDPs with the following characteristics are designated as rural areas:
                </P>
                <P>
                    • Population density of 2,000 or less per square kilometer that are clearly not urban in character (
                    <E T="03">e.g.,</E>
                     not an industrial/commercial area like a major airport, sportsplex, or a shopping center).
                </P>
                <P>• Population density greater than 2,000 per square kilometer that are contiguous to other census tracts, the majority of whose population densities is 2,000 or less.</P>
                <P>
                    <E T="03">Rural Partners Network Community Network</E>
                    —pre-selected geographic boundaries at the municipal level where the RPN pilot is serving to provide place-based assistance. The three RPN Community Networks in Puerto Rico are the Southwest Community Network, the Central Mountain Community Network, and the East Community Network. The Southwest Community Network is comprised of Mayaguez, Maricao, and Guánica; the Central Mountain Community Network is comprised of 9 municipalities: Utuado, Jayuya, Orocovis, Ciales, Villalba, Ponce, Adjuntas, Barranquitas, and Coamo; and the East Community Network is comprised of Fajardo, Ceiba, Naguabo, and El Yunque National Rainforest.
                </P>
                <P>
                    <E T="03">Technical assistance</E>
                    —Skilled help in improving the recipient's abilities in the areas of housing, community facilities, or community and economic planning development, including assistance with organizational structure, planning pre-award and post-award management, disaster recovery training in response to a Presidentially declared disaster, vacant and abandoned properties solutions, and drafting bylaws.
                </P>
                <P>
                    4. 
                    <E T="03">Application of Awards.</E>
                </P>
                <P>The Agency will review, evaluate, and score applications received in response to this notice based on the provisions indicated in this notice. Awards under this program will be made on a competitive basis using specific selection criteria contained in this notice. The Agency advises all interested parties that the applicant bears the full burden of the costs incurred in connection with the preparation and submission of an application in response to this notice.</P>
                <P>Awards under the Puerto Rico RPN RCDI Program are limited and are awarded through a competitive process. No reimbursement will be made for any funds expended prior to execution of the RCDI Grant Agreement and prior to the Agency's approval of recipients not identified in the application unless the intermediary is a nonprofit or educational entity and has requested and received written Agency approval of the costs prior to the actual expenditure. This exception is applicable for up to 90 days prior to grant closing and only applies to grantees that have received written approval but have not executed the Grant Agreement.</P>
                <P>The Agency cannot retroactively approve reimbursement for expenditures prior to execution of the Grant Agreement.</P>
                <HD SOURCE="HD1">B. Federal Award Information</HD>
                <P>Qualified private organizations, nonprofit organizations and public (including Tribal) intermediary organizations, located in Puerto Rico, proposing to carry out financial and technical assistance programs will be eligible to receive grant funding as an Intermediary under this program.</P>
                <P>
                    <E T="03">Type of Award:</E>
                     Grant.
                </P>
                <P>
                    <E T="03">Fiscal Year Funds:</E>
                     FY 2024.
                </P>
                <P>
                    <E T="03">Available Funds:</E>
                     A total of $1,000,000 will be made available to intermediaries proposing to serve areas in Puerto Rico affected by a disaster declared by the President.
                </P>
                <P>
                    <E T="03">Award Amounts:</E>
                     Grant funds are limited and are awarded through a competitive process. The maximum grant award amount available to an intermediary is $250,000. The intermediary must provide a program of financial and technical assistance to recipients to develop their capacity and ability to undertake projects related to housing, community facilities, or community and economic development that will support the community.
                </P>
                <P>
                    <E T="03">Anticipated Award Date:</E>
                     August 15, 2024.
                </P>
                <P>
                    <E T="03">Performance Period:</E>
                     Grant funds must be utilized within three years from the date of the award.
                </P>
                <P>The intermediary must provide a program of financial and technical assistance to one or more of the following: a nonprofit, low-income rural community, or local municipality, or a federally recognized tribe.</P>
                <P>
                    <E T="03">Renewal or Supplemental Awards:</E>
                     The Agency does not anticipate any additional awards.
                </P>
                <P>
                    <E T="03">Type of Assistance Instrument:</E>
                     Grant agreement.
                </P>
                <HD SOURCE="HD1">C. Eligibility Information</HD>
                <P>
                    1. 
                    <E T="03">Eligible Applicants.</E>
                     Applicants must meet all the following eligibility requirements by the application deadline. Applications that fail to meet any of these requirements by the application deadline will be deemed ineligible, will not be evaluated further, and will not receive a federal award under this funding opportunity:
                </P>
                <P>(a) Qualified private organizations, nonprofit organizations (including faith-based organizations in accordance with 7 CFR part 16, community organizations and philanthropic foundations), and public (including Tribal) intermediary organizations are eligible applicants. Definitions that describe eligible organizations and other key terms are listed above in section A(3) “Definitions.”</P>
                <P>(b) The recipient must be a nonprofit community-based housing and development organization, a low-income rural community, municipality, or a federally recognized tribe within the selected fifteen (15) communities in the geographical of the Puerto Rico RPN (see Appendix A). There are no federally recognized tribes nor TDHEs in Puerto Rico.</P>
                <P>(c) Private nonprofit, faith, or community-based organizations must provide a certificate of incorporation and a certificate of good standing from the Secretary of State of the State of incorporation, or other similar and valid documentation of current nonprofit status. For low-income rural community recipients, the Agency requires evidence that the entity is a public body and census data verifying that the median household income of the community where the office receiving the financial and technical assistance is located is at, or below, 80 percent of the State ($21,967) or national median household income ($69,021), whichever is higher, and provide evidence documenting that the recipient is located within Puerto Rico RPN Community Networks.</P>
                <P>(d) Grant funds will be disbursed pursuant to relevant provisions of 2 CFR parts 200 and 400.</P>
                <P>(e) Grant funds will be disbursed on an advance or reimbursement basis.</P>
                <P>
                    (f) Successful applications will be selected by the Agency for funding and will be awarded from funds appropriated for the Puerto Rico RPN RCDI program.
                    <PRTPAGE P="41931"/>
                </P>
                <P>
                    2. 
                    <E T="03">Cost Sharing or Matching.</E>
                </P>
                <P>There are no cost sharing or matching requirements associated with this grant program.</P>
                <P>
                    3. 
                    <E T="03">Other Eligibility Requirements.</E>
                </P>
                <P>The Intermediary must be located in Puerto Rico. The recipient and beneficiary, but not the intermediary, must be in an eligible RPN rural area (see Appendix A). The physical location of the recipient's office that will be receiving the financial and technical assistance must be in an eligible RPN rural area. If the recipient is a low-income community, the median household income of the area where the office is located must be at or below 80 percent of the State ($21,967) or national median household income ($69,021), whichever is higher. The Puerto Rico Rural Development State Office can assist in determining the eligibility of an area.</P>
                <P>(a) Grant funds must be utilized in a timely manner to ensure that the goals and objectives of the program are met.</P>
                <P>(b) Individuals cannot be recipients.</P>
                <P>(c) The intermediary must provide a program of financial and technical assistance to the recipient.</P>
                <P>(d) The intermediary organization must have been legally organized for a minimum of three years and have at least three years prior experience working with private nonprofit community-based housing and development organizations, low-income rural communities, or tribal organizations in the areas of housing, community facilities, or community and economic development. The intermediary organization may contract with a nonaffiliated organization for not more than 49 percent of the awarded grant to provide the proposed technical assistance.</P>
                <P>(e) Proposals must be structured to utilize the grant funds within 3 years from the date of the award.</P>
                <P>(f) Each applicant, whether individually or jointly, may only submit one application for RCDI funds under this Notice.</P>
                <P>(g) The intermediary and the recipient cannot be the same entity. The recipient can be a related entity to the intermediary, if it meets the definition of a recipient, provided the relationship does not create a conflict of interest that cannot be resolved to Rural Development's satisfaction.</P>
                <P>
                    (1) 
                    <E T="03">Eligible activities:</E>
                </P>
                <HD SOURCE="HD2">Capacity Building</HD>
                <P>• Build grant writing, program application and post award management and reporting capacity.</P>
                <P>• Provide assistance to community based-organizations and other types of organizations that needs to formalize its organization—legal, administrative and financial capacity—including assisting with filing for System Award Management (SAM) and Unique Entity Identifier (UEI) registrations, and requirements.</P>
                <P>• Board training.</P>
                <HD SOURCE="HD2">Funding</HD>
                <P>• Assisting with completing a grant application in accordance with federal regulations.</P>
                <P>• Assisting with capacity assessment, planning, short, medium, long-term solutions and coordination of funding and service resources.</P>
                <P>• Assisting with completion of environmental reports and/or documentation required for submittal of applications.</P>
                <P>• Accessing alternative funding sources.</P>
                <P>• Funding identification program alignment and project management to include predevelopment grant writing, technical assistance, and post award management.</P>
                <HD SOURCE="HD2">Planning</HD>
                <P>• According to the need or project, developing the necessary planning instrument such as: Strategic plan development, Viability Plans, Community Resiliency Plans, Community Emergency Plans, and/or Feasibility Plans.</P>
                <P>• Developing successful community facilities.</P>
                <P>• Creating training tools, such as videos, workbooks, and reference guides.</P>
                <P>• Project coordination—of funding and service resources—and implementation program for the short-, medium- and long-term solutions.</P>
                <P>• Providing Professional service fees for a Project Manager/Coordinator for assistance or implementation of the plans.</P>
                <HD SOURCE="HD2">Relationship Building</HD>
                <P>• Align outreach and site visit coordination.</P>
                <P>• Engage with cultural, faith based and community stakeholders.</P>
                <P>• Create alliances and partnerships to leverage mutual interest, promote efficiency, innovation and collaboration.</P>
                <P>• Guide in the creation of a volunteer program.</P>
                <HD SOURCE="HD2">Municipal Support</HD>
                <P>• Planning, implementation strategies, project management, and identification of funds for community development projects and services.</P>
                <P>• Strengthen community empowerment organizations and structure for supporting community development.</P>
                <P>• Assist with Nuisance program development and strategies for providing affordable housing.</P>
                <P>• Assist with Childcare, elderly services and housing, ownership titles orientation as part of disaster preparedness, support disaster recovery and climate change awareness in community development projects.</P>
                <P>
                    (2) 
                    <E T="03">Eligible recipients are:</E>
                </P>
                <P>(a) A municipality of any of the fifteen (15) RPN municipalities that compose the community networks (see Annex), private nonprofit, a community-based organization, or a rural community located in a Puerto Rico RPN Community Network. Particularly, organizations that have a community development project, services or initiatives in a RPN Community Network and needs assistance and capacity building to be eligible for federal funding and/or to implement the project, service or initiative.</P>
                <P>(b) Recipients can benefit from more than one Puerto Rico RPN RCDI application; however, after grant selections are made, the recipient can only benefit from multiple RCDI-RPN grants if the type of financial and technical assistance the recipient will receive is not duplicative. The services described in multiple Puerto Rico RPN RCDI grant applications must have separate and identifiable accounts for compliance purposes.</P>
                <P>(c) If the recipient is a low-income rural community, identify the unit of government to which the financial and technical assistance will be provided. The financial and technical assistance must be provided to the organized unit of government representing that community, not the community at large.</P>
                <P>
                    (3) 
                    <E T="03">Intermediary requirements:</E>
                </P>
                <P>Grant funds must be utilized in a timely manner to ensure that the goals and objectives of the program are met.</P>
                <P>(a) The intermediary must have been legally organized for a minimum of three years.</P>
                <P>(b) The intermediary must provide a program of financial and technical assistance to the recipient.</P>
                <P>(c) The intermediary must provide the latest financial information to show the intermediary's financial viability to carry out the proposed work. A current audit report is preferred.</P>
                <P>
                    (d) The intermediary must provide evidence of their experience in successfully completing and administering similar activities for technical assistance and capacity building to municipalities, rural communities, nonprofit, community-based organizations, during the past 
                    <PRTPAGE P="41932"/>
                    three years in activities such as: SAM registrations, 501(c)(3) process, drafting bylaws, planning a community development project, implementing and managing a community project, searching for federal resources, drafting a successful proposal, financial planning, strategic planning, implementing a community empowerment approach, assessing and resolving on land ownership and title documentation, and a nuisance management program among others.
                </P>
                <HD SOURCE="HD1">D. Application and Submission Information</HD>
                <P>
                    1. 
                    <E T="03">Address to Request Application Package.</E>
                </P>
                <P>
                    Application information for electronic submissions may be found at 
                    <E T="03">https://www.grants.gov.</E>
                </P>
                <P>Applicants may also request paper application packages from the Puerto Rico Rural Development State Office located at 654 Muñoz Rivera Ave., Suite 601, San Juan, Puerto Rico 00918 or at (787) 766-5095.</P>
                <P>
                    2. 
                    <E T="03">Content and Form of Application Submission.</E>
                </P>
                <P>If the applicant is ineligible or the application is incomplete, the Agency will inform the applicant in writing of the decision, reasons therefore, and its appeal rights and no further evaluation of the application will occur.</P>
                <P>A complete application for Puerto Rico Rural Partners Network RCDI Program funds must include the following:</P>
                <P>(a) A summary page, double-spaced between items, listing the following:</P>
                <P>(This information should not be presented in narrative form.)</P>
                <P>• Applicant's name,</P>
                <P>• Applicant's address,</P>
                <P>• Applicant's telephone number,</P>
                <P>• Name of applicant's contact person, email address and telephone number,</P>
                <P>• County where applicant is located,</P>
                <P>• Congressional district number where applicant is located,</P>
                <P>• Amount of grant request, and</P>
                <P>• Proposed number and type of recipients.</P>
                <P>(b) A detailed Table of Contents containing page numbers for each component of the application.</P>
                <P>(c) A project overview including the following items, which will also be addressed separately and in detail under “Building Capacity and Expertise” of the “Evaluation Criteria.”</P>
                <P>The type of technical assistance to be provided to the recipients and how it will be implemented.</P>
                <P>• How the capacity and ability of the recipients will be improved.</P>
                <P>• The overall goals to be accomplished.</P>
                <P>• The benchmarks to be used to measure the success of the program.</P>
                <P>Benchmarks should be specific and quantifiable.</P>
                <P>• What deliverables and outcomes are expected to be produced from the technical assistance.</P>
                <P>• Define the process to provide mentorship and maintenance of efforts.</P>
                <P>• Describe the technical assistance provided to the recipient demonstrating at least 50 percent l interaction.</P>
                <P>• Timeline describing the proposed tasks to be accomplished and the schedule for the implementation.</P>
                <P>• Outreach activities proposed.</P>
                <P>(d) Organizational documents, such as a certificate of incorporation and a current good standing certification from the Secretary of State where the applicant is incorporated and other similar and valid documentation of current status, from the intermediary that confirms it has been legally organized for a minimum of three years as the applicant entity.</P>
                <P>The applicant must maintain documentation on file for a period of at least three years after grant closing except that the records shall be retained beyond the three-year period if audit findings have not been resolved.</P>
                <P>(e) The following information is required for each Recipient:</P>
                <P>Recipients do not have to be identified in the application, however, Recipients must be determined eligible by the Puerto Rico Rural Development State office prior to the Intermediary providing assistance to the Recipient.</P>
                <P>(1) Recipient's name,</P>
                <P>(2) Complete address (mailing and physical location, if different),</P>
                <P>(3) County where located,</P>
                <P>(4) Congressional district where recipient is located,</P>
                <P>(5) Contact person's name, email address and telephone number, and</P>
                <P>(6) Form RD 400-4, “Assurance Agreement.” If the Form RD 400-4 is not submitted for each recipient, the recipient will be considered ineligible.</P>
                <P>(f) Submit evidence that each recipient entity is eligible. Documentation must be submitted to verify recipient eligibility. Links to websites are not acceptable. Acceptable documentation varies depending on the type of recipient:</P>
                <P>
                    (1) 
                    <E T="03">Nonprofits</E>
                    —provide a current valid letter confirming nonprofit status from the Secretary of State of the State of incorporation, a current good standing certification from the Secretary of State of the State of incorporation, or other valid documentation of current nonprofit status of each recipient.
                </P>
                <P>A nonprofit recipient must provide evidence that it is a valid nonprofit when the intermediary applies for the RCDI grant. Organizations with pending requests for nonprofit designations are not eligible.</P>
                <P>
                    (2) 
                    <E T="03">Low-income rural community</E>
                    —provide evidence the entity is a public body (
                    <E T="03">e.g.,</E>
                     copy of Charter, relevant Acts of Assembly, relevant court orders (if created judicially) or other valid documentation), and 2021 American Community Survey (ACS) 5-year estimates (2017-2021 data set) data as evidence that the median household income is at, or below, 80 percent of either the State or national median household income. We will only accept data and printouts from 
                    <E T="03">https://data.census.gov/cedsci/.</E>
                </P>
                <P>
                    (3) 
                    <E T="03">Federally recognized Tribes</E>
                    —The 2024 list is available at 89 FR 944, pages 944-948 at the following link: 
                    <E T="03">https://www.govinfo.gov/content/pkg/FR-2024-01-08/pdf/2024-00109.pdf.</E>
                     For Tribes that received federal recognition status publication, outside the publication cited above, statutory citations and additional documentation will suffice.
                </P>
                <P>An intermediary proposing to serve one or more federally recognized Tribes must include a resolution of support with its application from the Tribes it proposes to serve. If the resolution of support is not submitted for each Tribe, the Tribe will be considered ineligible as a recipient. This requirement is being added to ensure collaboration during the application process between intermediaries and all Tribes that they propose to serve. There are no federally recognized tribes nor TDHEs in Puerto Rico.</P>
                <P>(g) Each of the “Evaluation Criteria” must be addressed specifically and individually by category. Present these criteria in narrative form. Narrative (not including attachments) must be limited to five pages per criterion.</P>
                <P>(h) A timeline identifying specific activities and proposed dates for completion.</P>
                <P>(i) A detailed project budget that includes the RCDI grant amount. This should be a line-item budget, by category. Categories such as salaries, administrative, other, and indirect costs that pertain to the proposed project must be clearly defined. Supporting documentation listing the components of these categories must be included. The budget should be dated as follows: year 1, year 2, and year 3, as applicable.</P>
                <P>
                    (j) The indirect cost category in the project budget should be used only when a grant applicant has a federally negotiated indirect cost rate. A copy of the current rate agreement must be provided with the application. Non-federal entities that have never received a negotiated indirect cost rate, except for 
                    <PRTPAGE P="41933"/>
                    those non-federal entities described in Appendix VII to Part 200—States and Local Government and Indian Tribe Indirect Cost Proposals, paragraph (D)(1)(b), may use the de minimis rate of 10 percent of modified total direct costs (MTDC).
                </P>
                <P>(k) Form SF-424, “Application for Federal Assistance.”</P>
                <P>(Do not complete Form SF-424A, “Budget Information.” A separate line-item budget should be presented as described in Letter (j) of this section.)</P>
                <P>(l) Certification of Non-Lobbying Activities, RD Instruction 1940-Q Exhibit A-1, “Certification for Contracts, Grants and Loans” or equivalent.</P>
                <P>(m) Standard Form LLL, “Disclosure of Lobbying Activities,” if applicable.</P>
                <P>
                    Applicants must collect and maintain data provided by recipients on race, sex, and national origin and ensure Ultimate Recipients collect and maintain this data. Race and ethnicity data will be collected in accordance with OMB 
                    <E T="04">Federal Register</E>
                     notice, “Revisions to the Standards for the Classification of Federal Data on Race and Ethnicity” (62 FR 58782), October 30, 1997. Sex data will be collected in accordance with Title IX of the Education Amendments of 1972. These items should not be submitted with the application but should be available upon request by the Agency.
                </P>
                <P>The applicant and the recipient must comply with Title VI of the Civil Rights Act of 1964, Title IX of the Education Amendments of 1972, the Americans with Disabilities Act (ADA), section 504 of the Rehabilitation Act of 1973, the Age Discrimination Act of 1975, Executive Order 12250, Executive Order 13166 Limited English Proficiency (LEP), and 7 CFR part 1901, subpart E.</P>
                <P>(n) Identify and report any association or relationship with Rural Development employees. (A statement acknowledging whether or not a relationship exists is required.)</P>
                <P>
                    3. 
                    <E T="03">System for Award Management and Unique Entity Identifier.</E>
                </P>
                <P>
                    At the time of application, each applicant must have an active registration in the System for Award Management (SAM) before submitting its application in accordance with 2 CFR part 25 (
                    <E T="03">https://www.ecfr.gov/current/title-2/subtitle-A/chapter-I/part-25</E>
                    ). In order to register in SAM, entities will be required to obtain a Unique Entity Identifier (UEI). Instructions for obtaining the UEI are available at 
                    <E T="03">https://sam.gov/content/entity-registration.</E>
                </P>
                <P>(a) Applicants must maintain an active SAM registration, with current, accurate and complete information, at all times during which it has an active federal award or an application under consideration by a federal awarding agency.</P>
                <P>(b) Applicants must ensure they complete the Financial Assistance General Certifications and Representations in SAM.</P>
                <P>
                    (c) Each Applicant must provide a valid UEI in its application, unless determined exempt under 2 CFR 25.110 (
                    <E T="03">https://www.ecfr.gov/current/title-2/subtitle-A/chapter-I/part-25/subpart-A/section-25.110</E>
                    ).
                </P>
                <P>(d) Each applicant must provide documentation that it is registered in SAM and include its UEI number. If the applicant does not provide documentation confirming that it is registered in SAM and its UEI number, the application will not be considered for funding.</P>
                <P>(e) The Agency will not make an award until the applicant has complied with all SAM requirements including providing the UEI. If an applicant has not fully complied with the requirements by the time the Agency is ready to make an award, the Agency may determine that the applicant is not qualified to receive a federal award and use that determination as a basis for making a Federal award to another applicant.</P>
                <P>
                    4. 
                    <E T="03">Submission Dates and Times.</E>
                </P>
                <P>Completed applications must be submitted using one of the following methods:</P>
                <P>
                    <E T="03">Paper submissions:</E>
                     Paper application must be received by 4:00 p.m. local time by the Puerto Rico Rural Development State Office located at 654 Muñoz Rivera Ave., Suite 601, San Juan, Puerto Rico 00918, on July 3, 2024. Applicants intending to mail applications must provide sufficient time to permit delivery on or before the closing deadline date and time. Acceptance by the United States Postal Service or private mailer does not constitute delivery. Facsimile (FAX), electronic mail, and postage due applications will not be accepted. The application dates and times are firm. The Agency will not consider any application received after the deadline. To submit a paper application, the original application package must be submitted to the Puerto Rico Rural Development State Office located at 654 Muñoz Rivera Ave., Suite 601, San Juan, Puerto Rico 00918. The applicant should contact the Puerto Rico Rural Development State Office to see if applications may be submitted to Field Offices.
                </P>
                <P>Applicants may also request paper application packages from the Puerto Rico Rural Development State office at 654 Muñoz Rivera Ave., Suite 601, San Juan, Puerto Rico 00918, or (787) 766-5095.</P>
                <P>
                    <E T="03">Electronic submissions:</E>
                     Applications will not be accepted via FAX or electronic mail. Applicants may file an electronic application at 
                    <E T="03">https://www.grants.gov.</E>
                     Application information for electronic submissions may be found at 
                    <E T="03">https://www.Grants.gov/.</E>
                     Electronic applications must be submitted via 
                    <E T="03">Grants.gov</E>
                     by 11:59 p.m. Eastern Time on June 28, 2024. The application dates and times are firm. The Agency will not consider any application received after the deadline. Follow the instructions at 
                    <E T="03">Grants.gov</E>
                     for registering and submitting an electronic application. If a system problem or technical difficulty occurs with an electronic application, please use the customer support resources available at the 
                    <E T="03">Grants.gov</E>
                     website.
                </P>
                <P>
                    Technical difficulties applying through 
                    <E T="03">Grants.gov</E>
                     will not be a reason to extend the application deadline. If an application is unable to be submitted through 
                    <E T="03">Grants.gov,</E>
                     a paper application must be received in the Puerto Rico Rural Development State Office by the deadline noted previously.
                </P>
                <P>
                    5. 
                    <E T="03">Intergovernmental Review.</E>
                </P>
                <P>
                    Executive Order (E.O.) 12372, “Intergovernmental Review of Federal Programs,” applies to this program. This E.O. requires that Federal agencies provide opportunities for consultation on proposed assistance with State and local governments. Many states have established a Single Point of Contact (SPOC) to facilitate this consultation. For a list of States that maintain a SPOC, please see the White House website: 
                    <E T="03">https://www.whitehouse.gov/omb/management/office-federal-financial-management/.</E>
                     If your State has a SPOC, you may submit a copy of the application directly for review. Any comments obtained through the SPOC must be provided to your State Office for consideration as part of your application. If your state has not established a SPOC, you may submit your application directly to the Agency. Applications from Federally recognized Indian Tribes are not subject to this requirement. There are no federally recognized tribes nor TDHEs in Puerto Rico.
                </P>
                <P>
                    6. 
                    <E T="03">Funding Restrictions.</E>
                </P>
                <P>
                    The following are examples of eligible and ineligible purposes under the Puerto Rico RPN RCDI program. Activities that meet the objectives of the Puerto Rico RPN RCDI program and meet the criteria outlined in this Notice will be considered eligible. These examples are illustrative and are not 
                    <PRTPAGE P="41934"/>
                    meant to limit the activities proposed in the application:
                </P>
                <P>(a) The intermediary must work directly with the recipient, not the ultimate beneficiaries. For example:</P>
                <P>The intermediary provides training and technical assistance to the recipients on developing and updating materials related to the prevention, treatment and recovery activities for opioid use disorder and ensures that high-quality training is provided to communities affected by the opioid epidemic.</P>
                <P>(b) The intermediary provides training to the recipient on how to conduct homeownership education classes. The recipient then provides ongoing homeownership education to the residents of the community—the ultimate beneficiaries. This “train the trainer” concept fully meets the intent of this initiative. The intermediary is providing technical assistance that will build the recipient's capacity by enabling it to conduct homeownership education classes for the public. This is an eligible purpose. However, if the intermediary directly provided homeownership education classes to individuals in the recipient's service area, this would not be an eligible purpose because the recipient would be bypassed.</P>
                <P>(c) If the intermediary is working with a low-income community as the recipient, the intermediary must provide the technical assistance to the entity that represents the low-income community and is identified in the application.</P>
                <P>If the intermediary provides technical assistance to the Board of the low-income community on how to establish a cooperative, this would be an eligible purpose. However, if the intermediary works directly with individuals from the community to establish the cooperative, this is not an eligible purpose.</P>
                <P>The recipient's capacity is built by learning skills that will enable it to support sustainable economic development in its community on an ongoing basis.</P>
                <P>(d) The intermediary may provide technical assistance to the recipient on how to create and operate a revolving loan fund. The intermediary may not monitor or operate the revolving loan fund. RCDI funds cannot be used to fund revolving loan funds.</P>
                <P>(e) The intermediary may work with recipients to build their capacity to provide planning and leadership development training. The recipients of this training would be expected to assume leadership roles in the development and execution of regional strategic plans. The intermediary would work with multiple recipients in helping communities recognize their connections to the greater regional and national economies.</P>
                <P>(f) The intermediary could provide training and technical assistance to the recipients on developing emergency shelter and feeding, short-term housing, search and rescue, and environmental accident, prevention, and cleanup program plans. For longer term disaster and economic crisis responses, the intermediary could work with the recipients to develop job placement and training programs and develop coordinated transit systems for displaced workers.</P>
                <P>
                    7. 
                    <E T="03">Other Submission Requirements.</E>
                </P>
                <P>Fund uses must be consistent with the Puerto Rico RPN RCDI purpose. Eligible purposes of grant funds include, but are not limited to, the following:</P>
                <P>
                    (a) Provide technical assistance to develop recipients' capacity and ability to undertake projects related to housing, community facilities, or community and economic development, (
                    <E T="03">e.g.,</E>
                     the intermediary hires a staff person to provide technical assistance to the recipient or the recipient hires a staff person, under the supervision of the intermediary, to carry out the technical assistance provided by the intermediary). Hiring must support the intermediary's training purpose. Additional staff can be hired as a secondary purpose needed to carry out technical assistance/training to the recipient and must support the intermediary's training purpose.
                </P>
                <P>
                    (b) Develop the capacity of recipients to conduct community development programs, (
                    <E T="03">e.g.,</E>
                     homeownership education or training for business entrepreneurs).
                </P>
                <P>
                    (c) Develop the capacity of recipients to conduct developmental initiatives (
                    <E T="03">e.g.,</E>
                     programs that support micro-enterprise and sustainable development).
                </P>
                <P>(d) Develop the capacity of recipients to increase their leveraging ability and access to alternative funding sources by providing training and staffing.</P>
                <P>(e) Develop the capacity of recipients to provide the technical assistance component for essential community facilities projects.</P>
                <P>
                    (f) Assist recipients in completing pre-development requirements for housing, community facilities, or community and economic development projects by providing resources for professional services, 
                    <E T="03">e.g.,</E>
                     architectural, engineering, or legal. While this is an eligible purpose, applicant needs to ensure the capacity of the recipient is being expanded with appropriate training during the process.
                </P>
                <P>(g) Improve recipient's organizational capacity by providing training and resource material on developing strategic plans, board operations, management, financial systems, and information technology.</P>
                <P>(h) Purchase of computers, software, and printers is limited to $10,000 per award at the recipient level when directly related to the technical assistance program being undertaken by the intermediary.</P>
                <P>(i) Provide funds to recipients for training-related travel costs and training expenses related to Puerto Rico RPN RCDI.</P>
                <P>The following is a list of ineligible uses of grant funds:</P>
                <P>• Pass-through grants, and any funds provided to the recipient in a lump sum that are not reimbursements.</P>
                <P>• Funding a revolving loan fund (RLF).</P>
                <P>• Construction (in any form).</P>
                <P>• Salaries for positions involved in construction, renovations, rehabilitation, and any oversight of these types of activities.</P>
                <P>• Intermediary preparation of strategic plans for recipients.</P>
                <P>• Funding prostitution, gambling, or any illegal activities.</P>
                <P>• Grants to individuals.</P>
                <P>• Funding a grant where there may be a conflict of interest, or an appearance of a conflict of interest, involving any action by the Agency.</P>
                <P>• Paying obligations incurred before the beginning date without prior Agency approval or after the ending date of the grant agreement.</P>
                <P>• Purchasing real estate.</P>
                <P>• Improvement or renovation of the grantee or recipient's office space or for the repair or maintenance of privately-owned vehicles.</P>
                <P>• Any purpose prohibited in 2 CFR part 200 or 400.</P>
                <P>• Using funds for recipient's general operating costs.</P>
                <P>• Using grant funds for Individual Development Accounts.</P>
                <P>• Purchasing vehicles.</P>
                <P>• In accordance with 31 U.S.C. 1345, “Expenses of Meetings,” appropriations may not be used for travel, transportation, and subsistence expenses for a meeting. RCDI grant funds cannot be used for these meeting-related expenses.</P>
                <P>RCDI funds may be used to pay for a speaker as part of a program, equipment to facilitate the program, and the actual room that will house the meeting.</P>
                <P>
                    RCDI funds cannot be used for meetings; they can, however, be used for travel, transportation, or subsistence 
                    <PRTPAGE P="41935"/>
                    expenses for program-related training and technical assistance purposes. Any training not delineated in the application must be approved by the Agency to verify compliance with 31 U.S.C. 1345. Travel and per diem expenses (including meals and incidental expenses) will be allowed in accordance with 2 CFR parts 200 and 400.
                </P>
                <HD SOURCE="HD1">E. Application Review Information</HD>
                <P>
                    1. 
                    <E T="03">Criteria.</E>
                </P>
                <P>All eligible and complete applications will be evaluated and scored based on the selection criteria and weights contained in this Notice. Failure to address any of the application criteria by the application deadline will result in the application being determined ineligible, and the application will not be considered for funding.</P>
                <P>All applications that are complete and eligible will be scored and ranked competitively. The categories for scoring criteria used are the following:</P>
                <P>
                    (a) 
                    <E T="03">Building Capacity and Expertise</E>
                    —Maximum 40 Points
                </P>
                <P>The applicant must demonstrate how it will improve the recipients' capacity, through a program of financial and technical assistance, as it relates to the Puerto Rico RPN RCDI Program purposes.</P>
                <P>
                    Capacity—Building financial and technical assistance should provide new functions to the recipients or expand existing functions that will enable the recipients to undertake projects in the areas of housing, community facilities, or community and economic development that will benefit the community. Capacity-building financial and technical assistance may include, but is not limited to: training to conduct community development programs (
                    <E T="03">e.g.,</E>
                     homeownership education, or the establishment of minority business entrepreneurs, cooperatives, or micro-enterprises); organizational development (
                    <E T="03">e.g.,</E>
                     assistance to develop or improve board operations, management, and financial systems); instruction on how to develop and implement a strategic plan; instruction on how to access alternative funding sources to increase leveraging opportunities; and, staffing (
                    <E T="03">e.g.,</E>
                     hiring a person at intermediary or recipient level to provide technical assistance to recipients).
                </P>
                <P>The program of financial and technical assistance that is to be provided, its delivery, and the measurability of the program's effectiveness will determine the merit of the application.</P>
                <P>All applications will be competitively ranked and the applications providing the most improvement in capacity development and measurable activities being ranked the highest.</P>
                <P>The narrative response must contain the following items. This list also contains the points for each item.</P>
                <P>(1) Describe how the applicant will identify and will select the recipients in the RPN area and how the applicant will assess the recipient's needs for technical assistance and capacity building as described in purpose of the program (pages 6 to 8) (8 Points).</P>
                <P>(2) The scope of the technical assistance to be provided to the recipients and the activities that will be conducted to deliver the technical assistance, particularly providing customized-individualized technical assistance and capacity building (7 Points).</P>
                <P>(3) Identify which RCDI-RPN purpose areas will be addressed with this assistance: planning, project management, grant management and post award, development of bylaws, budgeting, financial planning, funding identification, implementation, community development and empowerment initiatives, grant eligibility and writing. (5 Points).</P>
                <P>(4) Describe how the results of the technical assistance will be measured and describe the benchmarks to be used to measure effectiveness. Benchmarks should be specific and quantifiable (10 Points).</P>
                <P>(5) Demonstrate that the applicant/intermediary has conducted programs of technical assistance and capacity building in rural communities, for municipalities, community-based organizations and nonprofits and achieved measurable results and best practices in successfully implementing and completing the community development project. (10 Points).</P>
                <P>
                    (b) 
                    <E T="03">Soundness of Approach</E>
                    —Maximum 15 Points
                </P>
                <P>The applicant can receive up to 15 points for soundness of approach. The overall proposal will be considered under this criterion.</P>
                <P>The maximum of 15 points for this criterion will be based on the following:</P>
                <P>(1) The proposal fits the objectives for which applications were invited, is clearly stated, and the applicant has defined how this proposal will be implemented (7 Points).</P>
                <P>(2) The ability to provide the proposed technical assistance and capacity building based on prior accomplishments (6 Points).</P>
                <P>(3) Cost effectiveness will be evaluated based on the budget in the application. The proposed grant amount and matching funds should be utilized to maximize capacity building at the recipient level (2 Points).</P>
                <P>
                    (c) 
                    <E T="03">RPN Community Network—15 Points</E>
                </P>
                <P>The RPN Community Network is defined as the boundaries of the three Community Networks. The Southwest Community Network is comprised of Mayaguez, Maricao, and Guánica; the Central Mountain Community Network is comprised of 9 municipalities: Utuado, Jayuya, Orocovis, Ciales, Villalba, Ponce, Adjuntas, Barranquitas, and Coamo; and the Eastern Community Network is comprised of Fajardo, Ceiba, Naguabo, and El Yunque National Rainforest.</P>
                <P>The applicant must indicate the targeted group that will benefit from the technical assistance and capacity building within the Community Network and will be scored as follows in the table illustrated below:</P>
                <GPOTABLE COLS="2" OPTS="L2,tp0,i1" CDEF="s150,10">
                    <TTITLE> </TTITLE>
                    <BOXHD>
                        <CHED H="1">Type of recipient</CHED>
                        <CHED H="1">
                            Scoring
                            <LI>(points)</LI>
                        </CHED>
                    </BOXHD>
                    <ROW>
                        <ENT I="01">Community Based Organization (minimum 6)</ENT>
                        <ENT>4</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Combination of municipality, community-based organization and Not-For Profit (minimum 5)</ENT>
                        <ENT>4</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Combination of Community-based organization and nonprofits (minimum 5)</ENT>
                        <ENT>3</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Not-For Profit (minimum 7)</ENT>
                        <ENT>3</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Municipalities (minimum 3)</ENT>
                        <ENT>1</ENT>
                    </ROW>
                </GPOTABLE>
                <PRTPAGE P="41936"/>
                <P>The applicant must indicate in the work description which areas of technical assistance they will provide:</P>
                <GPOTABLE COLS="2" OPTS="L2,tp0,i1" CDEF="s150,10">
                    <TTITLE> </TTITLE>
                    <BOXHD>
                        <CHED H="1">Type of technical assistance</CHED>
                        <CHED H="1">
                            Scoring
                            <LI>(percent)</LI>
                        </CHED>
                    </BOXHD>
                    <ROW>
                        <ENT I="01">
                            <E T="03">Capacity building</E>
                        </ENT>
                        <ENT>40</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Build grant writing, program application and post award management and reporting capacity.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="05">a. Train, mentors, one-on-one assistance with organizations to write successful grant applications or proposals.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="05">b. Assist with completing a grant application in accordance with federal regulations.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Provide assistance to community based-organizations and other types of organizations that need to formalize its organization—legal, administrative and financial capacity—including assisting with filing for System Award Management (SAM) and Unique Entity Identifier (UEI) registrations, and requirements.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="05">a. Prepare organizations to apply for and receive federal funding (SAMS, UEI).</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Board training.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="05">a. Identification, selection and creation of the board of directors.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="05">b. Draft by-laws.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Funding:</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="05">a. Assist in the capacity assessment, planning, short, medium, long-term solutions and coordination of funding and service resources.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="05">b. Assisting with the identification of environmental reports and/or documentation required for submittal of applications.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="05">c. Identifying funding sources for matching or grants based on reimbursement.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="05">d. Developing cost estimates</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="05">e. Guidance to define administrative cost.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">
                            <E T="03">Planning</E>
                        </ENT>
                        <ENT>20</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• According to the need or project, developing the necessary planning instrument such as: Strategic plan development, Viability plans, Community Resiliency Plans, Community Emergency Plans, and/or Feasibility Plans.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Developing successful community facilities.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Creating training tools, such as videos, workbooks, and reference guides.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Project coordination—of funding and service resources—and implementation program for the short-, medium- and long-term solutions.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Professional service fees for a Project Manager/Coordinator for assistance or implementation of the plans.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Creation of action plans for project deployment.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">
                            <E T="03">Relationship building</E>
                        </ENT>
                        <ENT>20</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Align outreach and site visit coordination.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Engagement with cultural, faith-based and community stakeholders.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Creating alliances and partnerships to leverage mutual interest, promote efficiency, innovation and collaboration.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Guide in the creation of a volunteer program.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Municipal Support:</ENT>
                        <ENT>20</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Planning implementation strategies, project management, and identification of funds for community development projects and services.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Strength community empowerment organizations and structure for supporting community development.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Nuisance program development and strategies for providing affordable housing.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">• Childcare, elderly services and housing, ownership titles orientation as part of disaster preparedness, support disaster recovery and climate change awareness in community development projects.</ENT>
                    </ROW>
                </GPOTABLE>
                <P>
                    (d) 
                    <E T="03">State Director's Points</E>
                    —Maximum 30 Points
                </P>
                <P>The State Director may award up to 30 discretionary points for projects to address items such as geographic distribution of funds, emergency conditions caused by economic problems, natural disasters and other initiatives identified by the Secretary. The State Director may also award points to any application that will advance the following key priorities:</P>
                <P>
                    (1) 
                    <E T="03">Addressing Climate Change and Environmental Justice:</E>
                     Reducing climate pollution and increasing resilience to the impacts of climate change through economic support to rural communities. Applicants may receive priority points addressing climate change in three ways:
                </P>
                <P>
                    <E T="03">Option 1:</E>
                     Applicants will receive points if the project is located in or serves a Disadvantaged Community as defined by the Climate and Economic Justice Screening Tool (CEJST), from the White House Council on Environmental Quality (CEQ). CEJST is a tool to help Federal agencies identify disadvantaged communities that will benefit from programs included in the Justice40 initiative. Census tracts are considered disadvantaged if they meet the thresholds for at least one of the CEJST's eight (8) categories of burden: Climate, Energy, Health, Housing, Legacy Pollution, Transportation, Water and Wastewater, or Workforce Development.
                </P>
                <P>
                    <E T="03">Option 2:</E>
                     Applicants will receive points if the project is located in or serves an Energy Community as defined by the Inflation Reduction Act (IRA). The IRA defines energy communities as:
                </P>
                <P>• A “brownfield site” (as defined in certain subparagraphs of the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA))</P>
                <P>• A “metropolitan statistical area” or “non-metropolitan statistical area” that has (or had at any time after 2009)</P>
                <P>• 0.17% or greater direct employment or 25% or greater local tax revenues related to the extraction, processing, transport, or storage of coal, oil, or natural gas; and has an unemployment rate at or above the national average unemployment rate for the previous year</P>
                <P>• A census tract (or directly adjoining census tract) in which a coal mine has closed after 1999; or in which a coal-fired electric generating unit has been retired after 2009.</P>
                <P>
                    <E T="03">Option 3:</E>
                     Applicants will receive points by demonstrating through written narrative how proposed climate-impact projects improve the livelihoods of community residents and meet pollution mitigation or clean energy goals.
                    <PRTPAGE P="41937"/>
                </P>
                <P>
                    Information on whether your project qualifies for priority points can be found at the following website: 
                    <E T="03">https://www.rd.usda.gov/priority-points.</E>
                </P>
                <P>
                    (2) 
                    <E T="03">Advancing Racial Justice, Place-Based Equity, and Opportunity:</E>
                     Ensuring all rural residents have equitable access to RD programs and benefits from RD funded projects.
                </P>
                <P>This priority aligns with the Executive Order on Advancing Racial Equity and Support for Underserved Communities Through the Federal Government. The Applicant receives priority points if the project is located in or serving a community with score 0.75 or above on the CDC Social Vulnerability Index. Please use Community Look-Up Map to look up map or list to determine if your project qualifies for priority points.</P>
                <P>US Territories are considered socially vulnerable and qualify for priority points.</P>
                <P>
                    Information on whether your project qualifies for priority points can be found at the following website: 
                    <E T="03">https://www.rd.usda.gov/priority-points.</E>
                </P>
                <P>
                    (3) 
                    <E T="03">Creating More and Better Markets:</E>
                     Assisting rural communities to recover economically through more and better market opportunities through improved infrastructure.
                </P>
                <P>
                    Applicants receive priority points if the project is located in or serving a rural community whose economic well-being ranks in the most distressed tier of the Distressed Communities Index. The Distressed Communities Index provides a score between 1-100 for every community at the zip code level. The most distressed tier of the index are those communities with a score over 80. Please use the Distressed Communities Index Look-Up Map to determine if your project qualifies for priority points by using the following link: 
                    <E T="03">http://www.rd.usda.gov/priority-points/rural-develoment-priorities-fy-2024.</E>
                     For additional information on data sources used for this priority determination, please download the Data Sources for Rural Development Priorities document.
                </P>
                <P>US Territories are considered distressed and qualify for priority points.</P>
                <P>
                    Information on whether your project qualifies for priority points can be found at the following website: 
                    <E T="03">https://www.rd.usda.gov/priority-points.</E>
                </P>
                <P>
                    <E T="03">2. Review and Selection Process.</E>
                </P>
                <P>If requests exceed funds available, the applications will be rated and ranked by a review panel based on the “Application Review Information” contained in this Notice.</P>
                <P>(a) If there is a tied score after the applications have been rated and ranked, the tie will be resolved by reviewing the scores for “Building Capacity and Expertise” and the applicant with the highest score in that category will receive a higher ranking. If the scores for “Building Capacity and Expertise” are the same, the scores will be compared for the next criterion, in sequential order, until the highest score can be determined. If all scores are equal Agency discretion applies.</P>
                <P>
                    (b) 
                    <E T="03">Initial screening:</E>
                     The Puerto Rico Rural Development State Office will screen each application to determine eligibility during the period immediately following the application deadline. Listed below are examples of reasons for rejection from previous funding rounds. The following reasons for rejection are not all inclusive; however, they represent the majority of the applications previously rejected.
                </P>
                <P>• Recipients were not located in eligible rural areas based on the definition in this Notice.</P>
                <P>
                    • Applicants failed to provide evidence of recipient's status, 
                    <E T="03">i.e.,</E>
                     documentation supporting nonprofit evidence of organization.
                </P>
                <P>• Application did not follow the RPN RCDI structure with an intermediary and recipients.</P>
                <P>• Intermediary did not provide evidence it had been incorporated for at least three years as the applicant entity.</P>
                <P>• Applicants failed to address the “Application Review Information” in this Notice.</P>
                <P>• The purpose of the proposal did not qualify as an eligible RPN RCDI purpose.</P>
                <P>
                    • Inappropriate use of funds (
                    <E T="03">e.g.,</E>
                     construction or renovations).
                </P>
                <P>• The applicant proposed providing financial and technical assistance directly to individuals.</P>
                <P>• The application package was not received by closing date and time.</P>
                <P>
                    <E T="03">3. Anticipated Announcement and Federal Award Dates.</E>
                </P>
                <P>August 15, 2024.</P>
                <HD SOURCE="HD1">F. Federal Award Administration Information</HD>
                <P>
                    <E T="03">1. Federal Award Notices.</E>
                </P>
                <P>Within the limit of funds available for such purpose, the awarding official of the Agency shall make grants in ranked order to eligible applicants under the procedures set forth in this Notice.</P>
                <P>Successful applicants will receive a selection letter by mail containing instructions on requirements necessary to proceed with execution and performance of the award. This letter is not an authorization to begin performance. In addition, selected applicants will be requested to verify that components of the application have not changed at the time of selection and on the award obligation date, if requested by the Agency.</P>
                <P>The award is not approved until all information has been verified, and the awarding official of the Agency has signed Form RD 1940-1, “Request for Obligation of Funds” and the grant agreement.</P>
                <P>Unsuccessful applicants will receive notification, including notification of appeal rights, by mail.</P>
                <P>
                    <E T="03">2. Administrative and National Policy Requirements.</E>
                </P>
                <P>Grantees will be required to do the following:</P>
                <P>(a) Execute a Rural Community Development Initiative Grant Agreement.</P>
                <P>(b) Execute Form RD 1940-1, “Request for Obligation of Funds.”</P>
                <P>(c) Use Form SF 270, “Request for Advance or Reimbursement,” to request reimbursements. Provide receipts for expenditures, timesheets and any other documentation to support the request for reimbursement.</P>
                <P>(d) Provide financial status and project performance reports on a quarterly basis starting with the first full quarter after the grant award.</P>
                <P>(e) Maintain a financial management system that is acceptable to the Agency.</P>
                <P>(f) Ensure that records are maintained to document all activities and expenditures utilizing RCDI grant funds and matching funds. Receipts for expenditures will be included in this documentation.</P>
                <P>(g) Provide annual audits or management reports on Form RD 442- 2, “Statement of Budget, Income and Equity,” and Form RD 442-3, “Balance Sheet,” depending on the amount of Federal funds expended and the outstanding balance.</P>
                <P>
                    (h) Collect and maintain data provided by recipients on race, sex, and national origin and ensure recipients collect and maintain the same data on beneficiaries. Race and ethnicity data will be collected in accordance with OMB 
                    <E T="04">Federal Register</E>
                     notice, “Revisions to the Standards for the Classification of Federal Data on Race and Ethnicity,” (62 FR 58782), October 30, 1997. Sex data will be collected in accordance with Title IX of the Education Amendments of 1972. These items should not be submitted with the application but should be available upon request by the Agency.
                </P>
                <P>(i) Provide a final project performance report.</P>
                <P>(j) Identify and report any association or relationship with Rural Development employees.</P>
                <P>
                    (k) The intermediary and recipient must comply with Title VI of the Civil Rights Act of 1964, Title IX of the 
                    <PRTPAGE P="41938"/>
                    Education Amendments of 1972, Section 504 of the Rehabilitation Act of 1973, Executive Order 12250, Age Act of 1975, Executive Order 13166 Limited English Proficiency, and 7 CFR part 1901, subpart E.
                </P>
                <P>(l) The grantee must comply with policies, guidance, and requirements as described in the following applicable Code of Federal Regulations, and any successor regulations:</P>
                <P>(1) 2 CFR parts 200 and 400 (Uniform Administrative Requirements, Cost Principles, and Audit Requirements for Federal Awards).</P>
                <P>(2) 2 CFR parts 417 and 180 (Government-wide Debarment and Suspension (Nonprocurement)).</P>
                <HD SOURCE="HD2">3. Reporting</HD>
                <P>After grant approval and through grant completion, you will be required to provide the following, as indicated in the Grant Agreement:</P>
                <P>(a) SF-425, “Federal Financial Report” and SF-PPR, “Performance Progress Report” will be required on a quarterly basis (due 30 working days after each calendar quarter). The Performance Progress Report shall include the elements described in the grant agreement.</P>
                <P>(b) Final financial and performance reports will be due 120 calendar days after the period of performance end date.</P>
                <P>(c) A summary at the end of the final report with elements as described in the grant agreement to assist in documenting the annual performance goals of the RPN RCDI program for Congress.</P>
                <HD SOURCE="HD1">G. Federal Awarding Agency Contacts</HD>
                <P>Contact the Puerto Rico Rural Development State Office at 654 Muñoz Rivera Ave., Suite 601, San Juan, Puerto Rico 00918, or (787) 766-5095.</P>
                <HD SOURCE="HD1">H. Other Information</HD>
                <HD SOURCE="HD2">1. Civil Rights Requirements</HD>
                <P>All grants made under this Notice are subject to Title VI of the Civil Rights Act of 1964 as required by the USDA in 7 CFR part 15, subpart A, Section 504 of the Rehabilitation Act of 1973, Title VIII of the Civil Rights Act of 1968, Title IX, Executive Order 13166 (Limited English Proficiency), Executive Order 11246, and the Equal Credit Opportunity Act of 1974.</P>
                <HD SOURCE="HD2">2. Paperwork Reduction Act</HD>
                <P>The paperwork burden has been approved by the Office of Management and Budget (OMB) under OMB Control Number 0575-0180.</P>
                <HD SOURCE="HD2">3. National Environmental Policy Act</HD>
                <P>
                    All recipients under this notice are subject to the requirements of 7 CFR part 1970, available at: 
                    <E T="03">https://rd.usda.gov/resources/environmental-studies/environmental-guidance.</E>
                </P>
                <HD SOURCE="HD2">4. Nondiscrimination Statement</HD>
                <P>In accordance with Federal civil rights laws and USDA civil rights regulations and policies, the USDA, its Mission Areas, agencies, staff offices, employees, and institutions participating in or administering USDA programs are prohibited from discriminating based on race, color, national origin, religion, sex, gender identity (including gender expression), sexual orientation, disability, age, marital status, family/parental status, income derived from a public assistance program, political beliefs, or reprisal or retaliation for prior civil rights activity, in any program or activity conducted or funded by USDA (not all bases apply to all programs). Remedies and complaint filing deadlines vary by program or incident.</P>
                <P>
                    Program information may be made available in languages other than English. Persons with disabilities who require alternative means of communication to obtain program information (
                    <E T="03">e.g.,</E>
                     Braille, large print, audiotape, American Sign Language) should contact the responsible Mission Area, agency, or staff office; or the 711 Federal Relay Service.
                </P>
                <P>
                    To file a program discrimination complaint, a complainant should complete a Form AD-3027, USDA Program Discrimination Complaint Form, which can be obtained online at, 
                    <E T="03">https://www.usda.gov/sites/default/files/documents/ad-3027.pdf</E>
                     from any USDA office, by calling (866) 632-9992, or by writing a letter addressed to USDA. The letter must contain the complainant's name, address, telephone number, and a written description of the alleged discriminatory action in sufficient detail to inform the Assistant Secretary for Civil Rights about the nature and date of an alleged civil rights violation. The completed AD-3027 form or letter must be submitted to USDA by:
                </P>
                <P>
                    (1) 
                    <E T="03">Mail:</E>
                     U.S. Department of Agriculture, Office of the Assistant Secretary for Civil Rights, 1400 Independence Avenue SW, Washington, DC 20250-9410; or
                </P>
                <P>
                    (2) 
                    <E T="03">Fax:</E>
                     (833) 256-1665 or (202) 690-7442; or
                </P>
                <P>
                    (3) 
                    <E T="03">Email: program.intake@usda.gov.</E>
                </P>
                <P>USDA is an equal opportunity provider, employer, and lender.</P>
                <SIG>
                    <NAME>Joaquin J. Altoro,</NAME>
                    <TITLE>Administrator, Rural Housing Service, USDA Rural Development.</TITLE>
                </SIG>
                <HD SOURCE="HD1">Appendix A: Rural Partners Network: Community Networks Puerto Rico</HD>
                <GPH SPAN="3" DEEP="172">
                    <GID>EN14MY24.113</GID>
                </GPH>
                <PRTPAGE P="41939"/>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10363 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3410-XV-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF COMMERCE</AGENCY>
                <SUBAGY>International Trade Administration</SUBAGY>
                <DEPDOC>[C-570-971]</DEPDOC>
                <SUBJECT>Multilayered Wood Flooring From the People's Republic of China: Final Results of Countervailing Duty Administrative Review; 2021</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Enforcement and Compliance, International Trade Administration, Department of Commerce.</P>
                </AGY>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The U.S. Department of Commerce (Commerce) continues to determine that the mandatory respondents, Riverside Plywood Corporation (Riverside) and Jiangsu Senmao Bamboo and Wood Industry Co., Ltd. (Jiangsu Senmao), and 12 other producers and/or exporters of multilayered wood flooring (wood flooring) from the People's Republic of China (China), received countervailable subsidies during the period of review (POR) January 1, 2021, through December 31, 2021.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Applicable May 14, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Craig Matney or Jonathan Schueler, AD/CVD Operations, Office VIII, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 1401 Constitution Avenue NW, Washington, DC 20230; telephone: (202) 482-2429 or (202) 482-9175, respectively.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">Background</HD>
                <P>
                    Commerce published the 
                    <E T="03">Preliminary Results</E>
                     of this administrative review in the 
                    <E T="04">Federal Register</E>
                     on December 28, 2023, and invited interested parties to comment.
                    <SU>1</SU>
                    <FTREF/>
                     On February 8, 2024, we received case briefs from the following interested parties: Riverside,
                    <SU>2</SU>
                    <FTREF/>
                     Jiangsu Senmao, the Government of the People's Republic of China (GOC), and the American Manufacturers of Multilayered Wood Flooring (AMMWF).
                    <SU>3</SU>
                    <FTREF/>
                     In addition, Commerce received a letter from Anhui Longhua Bamboo Product Co., Ltd.; Benxi Flooring Factory (General Partnership); Benxi Wood Company; Dalian Jiahong Wood Industry Co., Ltd.; Dalian Shengyu Science and Technology Development Co., Ltd.; Dongtai Fuan Universal Dynamics, LLC; HaiLin LinJing Wooden Products Co., Ltd.; Jiangsu Mingle Flooring Co., Ltd.; Jiangsu Simba Flooring Co., Ltd.; Jiangsu Yuhui International Trade Co., Ltd.; Jiashan On-Line Lumber Co., Ltd.; Kingman Wood Industry Co., Ltd.; Pinge Timber Manufacturing (Zhejiang) Co., Ltd.; Suzhou Dongda Wood Co., Ltd.; Tongxiang Jisheng Import and Export Co., Ltd.; Yihua Lifestyle Technology Co., Ltd.; Zhejiang Shiyou Timber Co., Ltd.; and Lumber Liquidators Services, LLC (collectively, CH Respondents) supporting arguments made by the mandatory respondents and the GOC.
                    <SU>4</SU>
                    <FTREF/>
                     On February 20, 2024, AMMWF, Riverside, and Jiangsu Senmao submitted timely rebuttal briefs.
                    <SU>5</SU>
                    <FTREF/>
                     Also on February 20, 2024, Commerce received a letter from the CH Respondents supporting the arguments presented in the rebuttal briefs by the GOC and the mandatory respondents.
                    <SU>6</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>1</SU>
                         
                        <E T="03">See Multilayered Wood Flooring from the People's Republic of China: Preliminary Results and Partial Rescission of Countervailing Duty Administrative Review; 2021,</E>
                         88 FR 89664 (December 28, 2023) (
                        <E T="03">Preliminary Results</E>
                        ), and accompanying Preliminary Decision Memorandum (PDM).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>2</SU>
                         We previously determined Baroque Timber (Zhongshan) Industries, Suzhou Times Flooring Co., Ltd., and Zhongshan Lianjia Flooring Co., Ltd. to be cross-owned affiliates of Riverside. 
                        <E T="03">See, e.g., Multilayered Wood Flooring from the People's Republic of China: Final Results of Countervailing Duty Administrative Review; 2020,</E>
                         88 FR 34828 (May 31, 2023).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>3</SU>
                         
                        <E T="03">See</E>
                         AMMWF's Letter, “Case Brief,” dated February 8, 2024; 
                        <E T="03">see</E>
                         also GOC's Letter, “GOC Case Brief,” dated February 8, 2024; Riverside's Letter, “Administrative Case Brief,” dated February 8, 2024; and Jiangsu Senmao's Letter, “Case Brief on behalf of Jiangsu Senmao Bamboo and Wood Industry Co., Ltd.,” dated February 8, 2024.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>4</SU>
                         
                        <E T="03">See</E>
                         CH Respondents' Letter, “Letter in Lieu of Case Brief,” dated February 8, 2024.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>5</SU>
                         
                        <E T="03">See</E>
                         AMMWF's Letter, “Rebuttal Brief,” dated February 20, 2024; 
                        <E T="03">see also</E>
                         Riverside's Letter, “Rebuttal Brief,” dated February 20, 2024; and Jiangsu Senmao's Letter, “Rebuttal Brief,” dated February 20, 2024.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>6</SU>
                         
                        <E T="03">See</E>
                         CH Respondents' Letter, “Letter in Lieu of Rebuttal Brief,” dated February 20, 2024.
                    </P>
                </FTNT>
                <HD SOURCE="HD1">Scope of the Order</HD>
                <P>
                    The product covered by the 
                    <E T="03">Order</E>
                     
                    <SU>7</SU>
                    <FTREF/>
                     is multilayered wood flooring from China. For a complete description of the scope of the 
                    <E T="03">Order, see</E>
                     the Issues and Decision Memorandum.
                    <SU>8</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>7</SU>
                         
                        <E T="03">See Multilayered Wood Flooring from the People's Republic of China: Countervailing Duty Order,</E>
                         76 FR 76693 (December 8, 2011); 
                        <E T="03">see also Multilayered Wood Flooring from the People's Republic of China: Amended Antidumping and Countervailing Duty Orders,</E>
                         77 FR 5484 (February 3, 2012); and 
                        <E T="03">Multilayered Wood Flooring from the People's Republic of China: Final Clarification of the Scope of the Antidumping and Countervailing Duty Orders,</E>
                         82 FR 27799 (June 19, 2017) (collectively, 
                        <E T="03">Order</E>
                        ).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>8</SU>
                         
                        <E T="03">See</E>
                         Memorandum, “Decision Memorandum for the Final Results of the Countervailing Duty Administrative Review of Multilayered Wood Flooring from the People's Republic of China; 2021,” dated concurrently with, and hereby adopted by, this notice (Issues and Decision Memorandum).
                    </P>
                </FTNT>
                <HD SOURCE="HD1">Analysis of Comments Received</HD>
                <P>
                    All issues raised in the parties' briefs are addressed in the Issues and Decision Memorandum. A list of the issues addressed is attached to this notice at Appendix I. The Issues and Decision Memorandum is a public document and is on file electronically via Enforcement and Compliance's Antidumping and Countervailing Duty Centralized Electronic Service System (ACCESS). ACCESS is available to registered users at 
                    <E T="03">https://access.trade.gov.</E>
                     In addition, a complete version of the Issues and Decision Memorandum can be accessed directly at 
                    <E T="03">https://access.trade.gov/public/FRNoticesListLayout.aspx.</E>
                </P>
                <HD SOURCE="HD1">Changes Since the Preliminary Results</HD>
                <P>
                    Based on our analysis of the case and rebuttal briefs and the evidence on the record, we made certain changes from the 
                    <E T="03">Preliminary Results,</E>
                     and we revised the net countervailable subsidy rates for Riverside and Jiangsu Senmao. These changes are explained in the Issues and Decision Memorandum.
                </P>
                <HD SOURCE="HD1">Methodology</HD>
                <P>
                    Commerce is conducting this review in accordance with section 751(a)(1)(A) of the Tariff Act of 1930, as amended (the Act). For each of the subsidy programs found countervailable, we find that there is a subsidy, 
                    <E T="03">i.e.,</E>
                     a government-provided financial contribution that gives rise to a benefit to the recipient, and that the subsidy is specific.
                    <SU>9</SU>
                    <FTREF/>
                     The Issues and Decision Memorandum contains a full description of the methodology underlying Commerce's conclusions, including any determination that relied upon the use of adverse facts available pursuant to sections 776(a) and (b) of the Act.
                </P>
                <FTNT>
                    <P>
                        <SU>9</SU>
                         
                        <E T="03">See</E>
                         sections 771(5)(B) and (D) of the Act regarding financial contribution; section 771(5)(E) of the Act regarding benefit; and section 771(5A) of the Act regarding specificity.
                    </P>
                </FTNT>
                <HD SOURCE="HD1">Rate for Non-Selected Companies Under Review</HD>
                <P>
                    The statute and Commerce's regulations do not address the establishment of a rate to be applied to companies not selected for individual examination when Commerce limits its examination in an administrative review pursuant to section 777A(e)(2) of the Act. However, Commerce normally determines the rates for non-selected companies in reviews in a manner that is consistent with section 705(c)(5) of the Act, which provides the basis for calculating the all-others rate in an investigation. Section 705(c)(5)(A)(i) of the Act instructs Commerce, as a general 
                    <PRTPAGE P="41940"/>
                    rule, to calculate the all-others rate equal to the weighted average of the countervailable subsidy rates established for exporters and producers individually investigated, excluding any zero or 
                    <E T="03">de minimis</E>
                     countervailable subsidy rates, and any rates determined entirely on the basis of facts available.
                </P>
                <P>
                    There are 12 companies for which a review was requested and not rescinded, and which were not selected as mandatory respondents or found to be cross-owned with a mandatory respondent. Because the rates calculated for the participating mandatory respondents in this review, Riverside and Jiangsu Senmao, were above 
                    <E T="03">de minimis</E>
                     and not entirely based on facts available, we calculated a rate for these 12 non-selected companies by weight-averaging the calculated subsidy rates of Riverside and Jiangsu Senmao using their publicly ranged sales data for exports of subject merchandise to the United States during the POR.
                    <SU>10</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>10</SU>
                         
                        <E T="03">See</E>
                         Memorandum, “Calculation of the Non-Selected Rate for the Final Results,” dated concurrently with this notice.
                    </P>
                </FTNT>
                <P>
                    This is the same methodology Commerce applied in the 
                    <E T="03">Preliminary Results</E>
                     for determining a rate for companies not selected for individual examination. However, due to changes in the calculations for Riverside and Jiangsu Senmao, we revised the non-selected rate accordingly. Consequently, for the 12 non-selected companies for which a review was requested and not rescinded, we are applying an 
                    <E T="03">ad valorem</E>
                     subsidy rate of 21.97 percent.
                </P>
                <HD SOURCE="HD1">Final Results of Administrative Review</HD>
                <P>We determine the countervailable subsidy rates for the mandatory and non-selected respondents under review for the period of January 1, 2021, through December 31, 2021, are as follows:</P>
                <GPOTABLE COLS="2" OPTS="L2,tp0,i1" CDEF="s200,12">
                    <TTITLE> </TTITLE>
                    <BOXHD>
                        <CHED H="1">Producer/exporter</CHED>
                        <CHED H="1">
                            Subsidy rate
                            <LI>
                                (percent 
                                <E T="03">ad valorem</E>
                                )
                            </LI>
                        </CHED>
                    </BOXHD>
                    <ROW>
                        <ENT I="01">
                            Riverside Plywood Corporation and Its Cross-Owned Affiliate
                            <SU>11</SU>
                        </ENT>
                        <ENT>30.85</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Jiangsu Senmao Bamboo and Wood Industry Co., Ltd.</ENT>
                        <ENT>5.39</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">
                            Non-Selected Companies Under Review
                            <SU>12</SU>
                        </ENT>
                        <ENT>21.97</ENT>
                    </ROW>
                </GPOTABLE>
                <HD SOURCE="HD1">
                    Disclosure
                    <FTREF/>
                </HD>
                <FTNT>
                    <P>
                        <SU>11</SU>
                         Cross-owned affiliates are Baroque Timber (Zhongshan) Industries, Suzhou Times Flooring Co., Ltd., and Zhongshan Lianjia Flooring Co., Ltd.
                    </P>
                    <P>
                        <SU>12</SU>
                         
                        <E T="03">See</E>
                         Appendix II.
                    </P>
                </FTNT>
                <P>
                    Commerce intends to disclose the calculations and analysis performed for these final results of review within five days of the date of publication of this notice in the 
                    <E T="04">Federal Register</E>
                    <E T="03">,</E>
                     in accordance with 19 CFR 351.224(b).
                </P>
                <HD SOURCE="HD1">Assessment Rates</HD>
                <P>
                    Pursuant to 19 CFR 351.212(b)(2), Commerce will determine, and U.S. Customs and Border Protection (CBP) shall assess, countervailing duties on all appropriate entries of subject merchandise in accordance with the final results of this review, for the above-listed companies at the applicable 
                    <E T="03">ad valorem</E>
                     assessment rates listed. We intend to issue assessment instructions to CBP 35 days after the date of publication of these final results of review. If a timely summons is filed at the U.S. Court of International Trade, the assessment instructions will direct CBP not to liquidate relevant entries until the time for parties to file a request for a statutory injunction has expired (
                    <E T="03">i.e.,</E>
                     within 90 days of publication).
                </P>
                <HD SOURCE="HD1">Cash Deposit Instructions</HD>
                <P>
                    In accordance with section 751(a)(2)(C) of the Act, Commerce also intends to instruct CBP to collect cash deposits of estimated countervailing duties in the amounts shown for each of the respective companies listed above on shipments of subject merchandise entered, or withdrawn from warehouse, for consumption on or after the date of publication of the final results of this administrative review. For all non-reviewed firms subject to the 
                    <E T="03">Order,</E>
                     we will instruct CBP to continue to collect cash deposits of estimated countervailing duties at the most recent company-specific or all-others rate applicable to the company, as appropriate. These cash deposit requirements, effective upon publication of these final results, shall remain in effect until further notice.
                </P>
                <HD SOURCE="HD1">Administrative Protective Order</HD>
                <P>This notice also serves as a reminder to parties subject to administrative protective order (APO) of their responsibility concerning the destruction of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of the return or destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and terms of an APO is a sanctionable violation.</P>
                <HD SOURCE="HD1">Notification to Interested Parties</HD>
                <P>We are issuing and publishing these final results in accordance with sections 751(a)(1) and 777(i)(1) of the Act, and 19 CFR 351.221(b)(5).</P>
                <SIG>
                    <DATED>Dated: May 7, 2024.</DATED>
                    <NAME>Ryan Majerus,</NAME>
                    <TITLE>Deputy Assistant Secretary for Policy and Negotiations, performing the non-exclusive functions and duties of the Assistant Secretary for Enforcement and Compliance.</TITLE>
                </SIG>
                <HD SOURCE="HD1">Appendix I—List of Topics Discussed in the Final Decision Memorandum</HD>
                <EXTRACT>
                    <FP SOURCE="FP-2">I. Summary</FP>
                    <FP SOURCE="FP-2">II. Background</FP>
                    <FP SOURCE="FP-2">III. Scope of the Order</FP>
                    <FP SOURCE="FP-2">IV. Non-Selected Companies Under Review</FP>
                    <FP SOURCE="FP-2">V. Period of Review</FP>
                    <FP SOURCE="FP-2">VI. Subsidies Valuation Information</FP>
                    <FP SOURCE="FP-2">VII. Changes Since the Preliminary Results</FP>
                    <FP SOURCE="FP-2">VIII. Use of Facts Otherwise Available</FP>
                    <FP SOURCE="FP-2">IX. Analysis of Programs</FP>
                    <FP SOURCE="FP-2">X. Discussion of the Issues</FP>
                    <FP SOURCE="FP1-2">Comment 1: Whether to Apply Adverse Facts Available (AFA) to the Export Buyer's Credit Program</FP>
                    <FP SOURCE="FP1-2">Comment 2: Whether to Apply AFA Regarding the Countervailability of the Provision of Electricity for Less Than Adequate Remuneration (LTAR)</FP>
                    <FP SOURCE="FP1-2">Comment 3: Whether to Apply AFA to Specificity Regarding the Countervailability of the Provision of Inputs for LTAR</FP>
                    <FP SOURCE="FP1-2">Comment 4: Whether Individually-Owned Suppliers Are Government Authorities</FP>
                    <FP SOURCE="FP1-2">Comment 5: Whether Commerce Should Exclude Certain International Tropical Timber Organization (ITTO) Data or Weight These Data Differently for the Wood Input Benchmarks</FP>
                    <FP SOURCE="FP1-2">A. Whether to Exclude Certain ITTO Data</FP>
                    <FP SOURCE="FP1-2">B. Whether Commerce Should Rely Only on the Tropical Timber Market Report (TTMR) Grade-Specific Prices to Value Plywood</FP>
                    <FP SOURCE="FP1-2">
                        C. Whether to Weight the ITTO's TTMR and Biennial Review Statistics (BRS) Data Using Country-Specific Averages
                        <PRTPAGE P="41941"/>
                    </FP>
                    <FP SOURCE="FP1-2">D. Whether to Include Domestic Brazilian Pricing Data in Tier Two World Market Benchmark Prices</FP>
                    <FP SOURCE="FP1-2">Comment 6: Whether to Revise the Veneer for LTAR Benchmark</FP>
                    <FP SOURCE="FP1-2">A. Whether to Include Harmonized System (HS) Subheading 4408.31</FP>
                    <FP SOURCE="FP1-2">B. Whether to Exclude HS Subheadings 4407.10 and 4407.11</FP>
                    <FP SOURCE="FP1-2">C. Whether to Exclude Certain Allegedly Aberrational Data from Singapore</FP>
                    <FP SOURCE="FP1-2">Comment 7: Whether to Revise the Plywood for LTAR Benchmark</FP>
                    <FP SOURCE="FP1-2">Comment 8: Whether to Rely on Certain Ocean Freight Benchmark Data Used to Calculate the Ocean Freight Benchmarks</FP>
                    <FP SOURCE="FP1-2">Comment 9: Whether Loans from Non-Chinese Owned Banks Are Countervailable</FP>
                    <FP SOURCE="FP1-2">Comment 10: Whether Commerce Made Ministerial Errors in the Subsidy Rate Calculations Pertaining to Various Provision of Inputs for LTAR Programs</FP>
                    <FP SOURCE="FP-2">XI. Recommendation</FP>
                </EXTRACT>
                <APPENDIX>
                    <HD SOURCE="HED">Appendix II—Non-Selected Companies Under Review</HD>
                    <FP SOURCE="FP-2">1. Dalian Penghong Floor Products Co., Ltd.</FP>
                    <FP SOURCE="FP-2">2. Dalian Shumaike Floor Manufacturing Co., Ltd.</FP>
                    <FP SOURCE="FP-2">
                        3. Fine Furniture (Shanghai) Limited 
                        <SU>13</SU>
                        <FTREF/>
                    </FP>
                    <FTNT>
                        <P>
                            <SU>13</SU>
                             Commerce previously found Great Wood (Tonghua) Ltd. and Fine Furniture Plantation (Shishou) Ltd. to be cross-owned with Fine Furniture (Shanghai) Limited. 
                            <E T="03">See Multilayered Wood Flooring from the People's Republic of China: Final Affirmative Countervailing Duty Determination,</E>
                            76 FR 64313 (October 18, 2011).
                        </P>
                    </FTNT>
                    <FP SOURCE="FP-2">4. Fusong Jinlong Wooden Group Co., Ltd.</FP>
                    <FP SOURCE="FP-2">5. Fusong Qianqiu Wooden Product Co., Ltd.</FP>
                    <FP SOURCE="FP-2">6. Huzhou Fulinmen Imp. &amp; Exp. Co., Ltd.</FP>
                    <FP SOURCE="FP-2">7. Huzhou Jesonwood Co., Ltd.</FP>
                    <FP SOURCE="FP-2">8. Jiangsu Guyu International Trading Co., Ltd.</FP>
                    <FP SOURCE="FP-2">9. Jiashan HuiJiaLe Decoration Material Co., Ltd.</FP>
                    <FP SOURCE="FP-2">10. Metropolitan Hardwood Floors, Inc.</FP>
                    <FP SOURCE="FP-2">11. Pinge Timber Manufacturing (Zhejiang) Co., Ltd.</FP>
                    <FP SOURCE="FP-2">12. Zhejiang Fuerjia Wooden Co., Ltd.</FP>
                </APPENDIX>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10512 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3510-DS-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF COMMERCE</AGENCY>
                <SUBAGY>National Oceanic and Atmospheric Administration</SUBAGY>
                <DEPDOC>[RTID 0648-XD929]</DEPDOC>
                <SUBJECT>Taking and Importing Marine Mammals; Taking Marine Mammals Incidental to the Lower Columbia River Dredged Material Management Plan, Oregon and Washington</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice; receipt of application for letter of authorization; request for comments and information.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>NMFS has received a request from the U.S. Army Corps of Engineers (USACE), Portland District, for authorization to take, by Level A and Level B harassment only, small numbers of marine mammals incidental to the Lower Columbia River (LCR) Dredged Material Management Plan (DMMP), in Oregon and Washington, for a period of 5 years from November 2028 through February 2032. Pursuant to regulations implementing the Marine Mammal Protection Act (MMPA), NMFS is announcing receipt of USACE's request for the development and implementation of regulations governing the incidental taking of marine mammals. NMFS invites the public to provide information, suggestions, and comments on USACE's application and request.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Comments and information must be received no later than June 13, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Comments on the application should be addressed to Jolie Harrison, Chief, Permits and Conservation Division, Office of Protected Resources, National Marine Fisheries Service. Physical comments should be sent to 1315 East-West Highway, Silver Spring, MD 20910 and electronic comments should be sent to 
                        <E T="03">ITP.Pauline@noaa.gov.</E>
                    </P>
                    <P>
                        <E T="03">Instructions:</E>
                         NMFS is not responsible for comments sent by any other method, to any other address or individual, or received after the end of the comment period. Comments received electronically, including all attachments, must not exceed a 25-megabyte file size. Attachments to electronic comments will be accepted in Microsoft Word or Excel or Adobe PDF file formats only. All comments received are a part of the public record and will generally be posted online at 
                        <E T="03">https://www.fisheries.noaa.gov/national/marine-mammal-protection/incidental-take-authorizations-construction-activities</E>
                         without change. All personal identifying information (
                        <E T="03">e.g.,</E>
                         name, address) voluntarily submitted by the commenter may be publicly accessible. Do not submit confidential business information or otherwise sensitive or protected information.
                    </P>
                    <P>
                        An electronic copy of USACE's application may be obtained online at: 
                        <E T="03">https://www.fisheries.noaa.gov/national/marine-mammal-protection/incidental-take-authorizations-construction-activities.</E>
                         In case of problems accessing these documents, please call the contact listed below.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Robert Pauline, Office of Protected Resources, NMFS, (301) 427-8401.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">Background</HD>
                <P>
                    Sections 101(a)(5)(A) and (D) of the MMPA (16 U.S.C. 1361 
                    <E T="03">et seq.</E>
                    ) direct the Secretary of Commerce (as delegated to NMFS) to allow, upon request, the incidental, but not intentional, taking of small numbers of marine mammals by U.S. citizens who engage in a specified activity (other than commercial fishing) within a specified geographical region if certain findings are made and either regulations are issued or, if the taking is limited to harassment, a notice of a proposed authorization is provided to the public for review.
                </P>
                <P>An incidental take authorization shall be granted if NMFS finds that the taking will have a negligible impact on the species or stock(s), will not have an immitigable adverse impact on the availability of the species or stock(s) for subsistence uses (where relevant), and if the permissible methods of taking and requirements pertaining to the mitigation, monitoring and reporting of such takings are set forth.</P>
                <P>NMFS has defined “negligible impact” in 50 CFR 216.103 as an impact resulting from the specified activity that cannot be reasonably expected to, and is not reasonably likely to, adversely affect the species or stock through effects on annual rates of recruitment or survival.</P>
                <P>The MMPA states that the term “take” means to harass, hunt, capture, kill or attempt to harass, hunt, capture, or kill any marine mammal.</P>
                <P>Except with respect to certain activities not pertinent here, the MMPA defines “harassment” as: any act of pursuit, torment, or annoyance, which (i) has the potential to injure a marine mammal or marine mammal stock in the wild (Level A harassment); or (ii) has the potential to disturb a marine mammal or marine mammal stock in the wild by causing disruption of behavioral patterns, including, but not limited to, migration, breathing, nursing, breeding, feeding, or sheltering (Level B harassment).</P>
                <HD SOURCE="HD1">Summary of Request</HD>
                <P>
                    On October 18, 2023, NMFS received an application from the USACE requesting authorization for take of marine mammals incidental to in-water construction activities associated with the LCR DMMP in Oregon and Washington between River Mile (RM) 23 and RM 36. We provided comments on the application and the USACE submitted a revised version on February 27, 2024. We deemed the application adequate and complete on April 25, 2024. The requested regulations under which we would issue the requested 
                    <PRTPAGE P="41942"/>
                    LOA would be valid for 5 years, November 2028 through February 2032. The USACE plans to construct new structures with pilings in the Lower Columbia River. The full DMMP includes proposed dredging and placement operations between RM 3 and RM 105.5. However, the scope of this request for a LOA is limited to potential pile driving that would be associated with any new structures installed under the DMMP which would occur between RM 23 and RM 36. In-water impact and vibratory pile driving of steel and timber piles may incidentally expose marine mammals to elevated levels of noise, thereby resulting in incidental take, by Level A and Level B harassment only. Therefore, the USACE requests authorization to incidentally take marine mammals.
                </P>
                <HD SOURCE="HD1">Specified Activities</HD>
                <P>
                    The purpose of the proposed project is to maintain the authorized LCR Federal Navigation Channel depth and width for a minimum of 20 years in the least cost, operationally feasible, and environmentally acceptable manner in order to provide continued reliable, safe, and efficient transportation of waterborne commerce and uninterrupted transit for fully loaded vessels in the LCR. The USACE anticipates 141 in-water work days will be required to install approximately 1,029, 12-inch timber piles and 1,038, 24-inch steel piles via impact and vibratory driving over 5 years. The number of in-water work days per year would range from 1 (Year 2) to 51 (Year 5). Take by Level A and Level B harassment has been requested for harbor seal (
                    <E T="03">Phoca vitulina richardii</E>
                    ), Steller sea lion (
                    <E T="03">Eumetopias jubatus</E>
                    ), and California sea lion (
                    <E T="03">Zalophus californianus</E>
                    ). The USACE's application contains mitigation and monitoring measures designed to reduce impacts to marine mammals. The application also contains proposed marine mammal monitoring and reporting plans.
                </P>
                <HD SOURCE="HD1">Information Solicited</HD>
                <P>
                    Interested persons may submit information, suggestions, and comments concerning USACE's request (see 
                    <E T="02">ADDRESSES</E>
                    ). NMFS will consider all information, suggestions, and comments related to the request during the development of proposed regulations governing the incidental taking of marine mammals by USACE, if appropriate.
                </P>
                <SIG>
                    <DATED>Dated: May 7, 2024.</DATED>
                    <NAME>Catherine Marzin,</NAME>
                    <TITLE>Deputy Director, Office of Protected Resources, National Marine Fisheries Service.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10423 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3510-22-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF COMMERCE</AGENCY>
                <SUBAGY>National Oceanic and Atmospheric Administration</SUBAGY>
                <SUBJECT>Agency Information Collection Activities; Submission to the Office of Management and Budget for Review and Approval; Comment Request; Documentation of Fish Harvest</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>National Marine Fisheries Service (NMFS), Commerce.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of information collection; request for comments.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Department of Commerce, in accordance with the Paperwork Reduction Act of 1995 (PRA), invites the general public and other Federal agencies to comment on proposed and continuing information collections, which helps us assess the impact of our information collection requirements and minimize the public's reporting burden. The purpose of this notice is to allow for 60 days of public comment preceding submission of the collection to the Office of Management and Budget (OMB) for review.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>To ensure consideration, comments regarding this proposed information collection must be received on or before July 15, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Interested persons are invited to submit written comments to Adrienne Thomas, NOAA PRA Officer, at 
                        <E T="03">noaa.pra@noaa.gov.</E>
                         Reference OMB Control Number 0648-0365 in the subject line of your comments. All comments received are part of the public record and will generally be posted on 
                        <E T="03">https://www.regulations.gov</E>
                         without change. Do not submit confidential business information or otherwise sensitive or protected information.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Requests for additional information or specific questions related to collection activities should be directed to Rick DeVictor, NMFS, Southeast Regional Office, Sustainable Fisheries Division, 263 13th Avenue South, St. Petersburg, Florida 33701, telephone: 727-824-5305, email: 
                        <E T="03">rick.devictor@noaa.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">I. Abstract</HD>
                <P>The NMFS Southeast Region proposes to extend the information collection currently approved under OMB Control Number 0648-0365, South Atlantic Documentation of Fish Harvest.</P>
                <P>The NMFS Southeast Region manages commercial fishing in Federal waters of the South Atlantic under the authority of the Magnuson-Stevens Fishery Conservation and Management Act (Magnuson-Stevens Act). South Atlantic Federal waters encompass the area offshore of North Carolina and south through the east coast of Florida.</P>
                <P>Federally permitted seafood dealers who process or sell federally managed snapper and grouper species during seasonal fishery closures in the South Atlantic for those applicable species must maintain documentation, as specified in 50 CFR part 300 subpart K and 50 CFR 622.192(i), that such fish were harvested from areas other than state or Federal waters in the South Atlantic. The applicable snapper and grouper species are greater amberjack, gag, black grouper, red grouper, scamp, red hind, rock hind, yellowmouth grouper, yellowfin grouper, graysby, and coney. The required documentation includes information about the vessel that harvested the fish, and where and when the fish were offloaded. The required documentation also requires a signed statement by the dealer that attests to the harvest of the applicable species from areas other than the South Atlantic. NMFS requires the information for the enforcement of fishery regulations at 50 CFR 622, subpart I.</P>
                <HD SOURCE="HD1">II. Method of Collection</HD>
                <P>The information is in the form of a paper affidavit that a dealer creates and retains.</P>
                <HD SOURCE="HD1">III. Data</HD>
                <P>
                    <E T="03">OMB Control Number:</E>
                     0648-0365.
                </P>
                <P>
                    <E T="03">Form Number(s):</E>
                     None.
                </P>
                <P>
                    <E T="03">Type of Review:</E>
                     Regular submission—extension of a current information collection.
                </P>
                <P>
                    <E T="03">Affected Public:</E>
                     Businesses or other for-profit organizations.
                </P>
                <P>
                    <E T="03">Estimated Number of Respondents:</E>
                     379.
                </P>
                <P>
                    <E T="03">Estimated Time per Response:</E>
                     10 minutes.
                </P>
                <P>
                    <E T="03">Estimated Total Annual Burden Hours:</E>
                     63 hours.
                </P>
                <P>
                    <E T="03">Estimated Total Annual Cost to Public:</E>
                     $0 in recordkeeping and reporting costs.
                </P>
                <P>
                    <E T="03">Respondent's Obligation:</E>
                     Mandatory.
                </P>
                <P>
                    <E T="03">Legal Authority:</E>
                     Magnuson-Stevens Act, 16 U.S.C. 1801 
                    <E T="03">et seq.</E>
                </P>
                <HD SOURCE="HD1">IV. Request for Comments</HD>
                <P>
                    We are soliciting public comments to permit the Department/Bureau to: (a) Evaluate whether the proposed 
                    <PRTPAGE P="41943"/>
                    information collection is necessary for the proper functions of the Department, including whether the information will have practical utility; (b) Evaluate the accuracy of our estimate of the time and cost burden for this proposed collection, including the validity of the methodology and assumptions used; (c) Evaluate ways to enhance the quality, utility, and clarity of the information to be collected; and (d) Minimize the reporting burden on those who are to respond, including the use of automated collection techniques or other forms of information technology.
                </P>
                <P>Comments that you submit in response to this notice are a matter of public record. We will include or summarize each comment in our request to OMB to approve this ICR. Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you may ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.</P>
                <SIG>
                    <NAME>Sheleen Dumas,</NAME>
                    <TITLE>Department PRA Clearance Officer, Office of the Under Secretary for Economic Affairs, Commerce Department.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10529 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3510-22-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF COMMERCE</AGENCY>
                <SUBAGY>National Oceanic and Atmospheric Administration</SUBAGY>
                <SUBJECT>Agency Information Collection Activities; Submission to the Office of Management and Budget (OMB) for Review and Approval; Comment Request; National Marine Sanctuary Permits</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>National Oceanic &amp; Atmospheric Administration (NOAA), Commerce.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of information collection, request for comment.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Department of Commerce, in accordance with the Paperwork Reduction Act of 1995 (PRA), invites the general public and other Federal agencies to comment on proposed and continuing information collections, which helps us assess the impact of our information collection requirements and minimize the public's reporting burden. This notice pertains to a requested revision and extension of the approved collection of information for national marine sanctuary permits. The purpose of this notice is to allow for 60 days of public comment preceding submission of the collection to Office of Management and Budget (OMB).</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>To ensure consideration, comments regarding this proposed information collection must be received on or before July 15, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Interested persons are invited to submit written comments to Adrienne Thomas, NOAA PRA Officer, at 
                        <E T="03">NOAA.PRA@noaa.gov.</E>
                         Please reference OMB Control Number 0648-0141 in the subject line of your comments. Do not submit Confidential Business Information or otherwise sensitive or protected information.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Requests for additional information or specific questions related to collection activities should be directed to Sophie De Beukelaer, National Permit Coordinator, National Oceanic and Atmospheric Administration, 99 Pacific Street, Building 455A, Monterey, CA 93940, 831-583-8755, and 
                        <E T="03">sophie.debeukelaer@noaa.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">I. Abstract</HD>
                <P>
                    This request is for revision and extension of a currently approved information collection by the Office of National Marine Sanctuaries (ONMS). ONMS manages national marine sanctuaries pursuant to the purposes and policies of the National Marine Sanctuaries Act (16 U.S.C. 1431 
                    <E T="03">et seq.</E>
                    ).
                </P>
                <P>National marine sanctuary regulations at 15 CFR part 922 list specific activities that are prohibited in national marine sanctuaries. These regulations also state that otherwise prohibited activities may be conducted if a permit is issued by ONMS. Persons desiring a permit must submit an application (note that requests for baitfish permits and Tortugas Ecological Reserve North Access permits require contacting Florida Keys National Marine Sanctuary and do not require a completed ONMS permit application), and anyone obtaining a permit is generally required to submit one or more reports on the activity allowed under the permit. The recordkeeping and reporting requirements at 15 CFR part 922 form the basis for this collection of information.</P>
                <P>This information is required by ONMS to protect and manage sanctuary resources. The permit application collects information about the proposed activities, the methods proposed to be used, the potential effects to sanctuary resources, and information on the regulatory review criteria at 15 CFR part 922. ONMS uses this information to evaluate whether the proposed activities are consistent with the goals and objectives of the sanctuary and the purposes and policies of the NMSA.</P>
                <P>Changes to this information collection include revisions to the permit application and instructions to collect information about small businesses to better assess the types of entities engaged in permitting activities. The estimated number of permits issued per year also changed from 424 to 567 to reflect the additional estimated permit numbers if the various proposed national marine sanctuary designations are finalized. In particular, this is based on adding an estimated fifteen additional permits and about 59 certifications for the proposed Chumash Heritage National Marine Sanctuary (88 FR 58123, August 25, 2023), an estimated five additional permits for the proposed designation of the National Marine Sanctuary for the Pacific Remote Islands (88 FR 23624; April 18, 2023), an estimated five additional permits for proposed Lake Ontario National Marine Sanctuary (88 FR 3334, January 19, 2023), an estimated five additional permits for proposed Lake Erie Quadrangle National Marine Sanctuary (88 FR 32198, July 18, 2023), an estimated nine permits for the proposed sanctuary in the Hudson Canyon area (87 FR 38387, June 8, 2022), and increasing the numbers of amendments and Tortugas access permits to reflect more recent average permit numbers. The number of baitfish permits was diminished by 35 permits and Florida Keys National Marine Sanctuary plans to phase out the bait fishing permits over the next three years (87 FR 42800, July 18, 2022).</P>
                <HD SOURCE="HD1">II. Method of Collection</HD>
                <P>Depending on the permit being requested, an application, reports, and telephone calls may be required from applicants. Applications and reports can be submitted via email, fax, or traditional mail. Applicants are encouraged to use electronic means to apply for permits and submit reports whenever possible.</P>
                <HD SOURCE="HD1">III. Data</HD>
                <P>
                    <E T="03">OMB Control Number:</E>
                     0648-0141.
                </P>
                <P>
                    <E T="03">Form Number(s):</E>
                     None.
                </P>
                <P>
                    <E T="03">Type of Review:</E>
                     Regular submission (revision and extension of a currently approved information collection).
                </P>
                <P>
                    <E T="03">Affected Public:</E>
                     Business or other for-profit organizations; individuals or households; not-for-profit institutions; Federal Government; State, local, or Tribal government.
                    <PRTPAGE P="41944"/>
                </P>
                <P>
                    <E T="03">Estimated Number of Respondents:</E>
                     567.
                </P>
                <P>
                    <E T="03">Estimated Time per Response:</E>
                     General permits and authorizations, 1 hour and 30 minutes; special use permits, 8 hours; historical resources permits, 13 hours; baitfish permits, 25 minutes; permit amendments and certifications, 30 minutes; voluntary registrations, 15 minutes; appeals, 24 hours; Tortugas access permits, 5 minutes.
                </P>
                <P>
                    <E T="03">Estimated Total Annual Burden Hours:</E>
                     2,307.75.
                </P>
                <P>
                    <E T="03">Estimated Total Annual Cost to Public:</E>
                     There are no capital/start-up or ongoing operation/maintenance costs associated with this information collection. The submission of information under this collection is primarily via email, phone, or fax and does not result in additional costs to the public.
                </P>
                <P>
                    <E T="03">Respondent's Obligation:</E>
                     Required to Obtain or Retain Benefits.
                </P>
                <P>
                    <E T="03">Legal Authority:</E>
                     16 U.S.C. 1431 
                    <E T="03">et seq.</E>
                </P>
                <HD SOURCE="HD1">IV. Request for Comments</HD>
                <P>We are soliciting public comments to permit the Department/Bureau to: (a) Evaluate whether the proposed information collection is necessary for the proper functions of the Department, including whether the information will have practical utility; (b) Evaluate the accuracy of our estimate of the time and cost burden for this proposed collection, including the validity of the methodology and assumptions used; (c) Evaluate ways to enhance the quality, utility, and clarity of the information to be collected; and (d) Minimize the reporting burden on those who are to respond, including the use of automated collection techniques or other forms of information technology.</P>
                <P>Comments that you submit in response to this notice are a matter of public record. We will include or summarize each comment in our request to OMB to approve this ICR. Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you may ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.</P>
                <SIG>
                    <NAME>Sheleen Dumas,</NAME>
                    <TITLE>Department PRA Clearance Officer, Office of the Under Secretary for Economic Affairs, Commerce Department.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10537 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3510-NK-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF COMMERCE</AGENCY>
                <SUBAGY>National Oceanic and Atmospheric Administration</SUBAGY>
                <SUBJECT>Agency Information Collection Activities; Submission to the Office of Management and Budget (OMB) for Review and Approval; Comment Request; Resident Perceptions of Offshore Wind Energy Development Off the Oregon Coast and Along the Gulf of Mexico</SUBJECT>
                <P>
                    The Department of Commerce will submit the following information collection request to the Office of Management and Budget (OMB) for review and clearance in accordance with the Paperwork Reduction Act of 1995, on or after the date of publication of this notice. We invite the general public and other Federal agencies to comment on proposed, and continuing information collections, which helps us assess the impact of our information collection requirements and minimize the public's reporting burden. Public comments were previously requested via the 
                    <E T="04">Federal Register</E>
                     on December 27, 2023 during a 60-day comment period. This notice allows for an additional 30 days for public comments.
                </P>
                <P>
                    <E T="03">Agency:</E>
                     National Oceanic and Atmospheric Administration, Commerce.
                </P>
                <P>
                    <E T="03">Title:</E>
                     Resident Perceptions of Offshore Wind Energy Development off the Oregon Coast and Along the Gulf of Mexico.
                </P>
                <P>
                    <E T="03">OMB Control Number:</E>
                     0648-0744.
                </P>
                <P>
                    <E T="03">Form Number(s):</E>
                     None.
                </P>
                <P>
                    <E T="03">Type of Request:</E>
                     Regular (Revision).
                </P>
                <P>
                    <E T="03">Number of Respondents:</E>
                </P>
                <P>
                    <E T="03">Oregon—Focus groups:</E>
                     48; 
                    <E T="03">Questionnaire:</E>
                     4,569.
                </P>
                <P>
                    <E T="03">Gulf of Mexico (TX and LA)—Focus groups:</E>
                     64; 
                    <E T="03">Questionnaire:</E>
                     4,925.
                </P>
                <P>
                    <E T="03">Total—Focus Groups:</E>
                     112; 
                    <E T="03">Questionnaire:</E>
                     9,494.
                </P>
                <P>
                    <E T="03">Average Hours per Response:</E>
                </P>
                <P>
                    <E T="03">Focus groups:</E>
                     1 hour; 
                    <E T="03">Questionnaire:</E>
                     20 minutes.
                </P>
                <P>
                    <E T="03">Total Annual Burden Hours:</E>
                </P>
                <P>
                    <E T="03">Oregon:</E>
                     1,571.
                </P>
                <P>
                    <E T="03">Gulf of Mexico (TX and LA):</E>
                     1,705.66.
                </P>
                <P>
                    <E T="03">Total:</E>
                     3,276.66.
                </P>
                <P>
                    <E T="03">Needs and Uses:</E>
                     This is a request for revision to an existing information collection. Pursuant to E.O. 14057 (Executive Order on Catalyzing Clean Energy Industries and Jobs Through Federal Sustainability), the Outer Continental Shelf Land Act, the National Environmental Policy Act, and the Coastal Zone Management Act, the requested revision will expand the existing data collection, which is currently focused on coastal Oregon, by adding a new geographical location, specifically, coastal Texas and Louisiana along the Gulf of Mexico.
                </P>
                <P>The Bureau of Ocean Energy Management (BOEM) held its first leasing auction for the Gulf of Mexico in August 2023. BOEM finalized four Wind Energy Areas (WEAs) in the Gulf of Mexico in October 2023. Outside of official public engagement forums, preferences about offshore wind energy development generally remain unknown for members of the public, as well as for groups who may not perceive themselves as stakeholders. Failure to gain the perspective of communities regarding potential benefits or impacts is problematic, particularly when latent stakeholders to local projects emerge late in the planning process.</P>
                <P>The National Ocean Service (NOS) proposes to expand collection of data on the opinions, values, and attitudes relative to offshore wind energy development to coastal residents of Texas and Louisiana along the Gulf of Mexico in addition to coastal Oregon. Respondents (age 18 years and older) will be randomly sampled from households in 39 coastal counties in Texas and Louisiana. This information will be used by NOAA, BOEM, and others to understand what is important to communities; understand how differing values and perceptions across communities influence local receptivity to proposed development; and improve communication efforts targeted to residents, enabling agencies to more effectively and efficiently direct outreach and community inclusion activities. NOAA has a vested interest in offshore wind energy development, from many perspectives, including as it relates to the resilience, well-being, and sustainability of coastal communities.</P>
                <P>
                    <E T="03">Affected Public:</E>
                     Individuals or households.
                </P>
                <P>
                    <E T="03">Frequency:</E>
                     Once.
                </P>
                <P>
                    <E T="03">Respondent's Obligation:</E>
                     Voluntary.
                </P>
                <P>
                    <E T="03">Legal Authority:</E>
                     NOAA's Programmatic Authority—Integrated Coastal and Ocean Observation System Act (33 U.S.C. 3601 
                    <E T="03">et seq.</E>
                    ); BOEM's Programmatic Authority—Outer Continental Shelf Lands Act (43 U.S.C. 1346).
                </P>
                <P>
                    This information collection request may be viewed at 
                    <E T="03">www.reginfo.gov.</E>
                      
                    <PRTPAGE P="41945"/>
                    Follow the instructions to view the Department of Commerce collections currently under review by OMB.
                </P>
                <P>
                    Written comments and recommendations for the proposed information collection should be submitted within 30 days of the publication of this notice on the following website 
                    <E T="03">www.reginfo.gov/public/do/PRAMain.</E>
                     Find this particular information collection by selecting “Currently under 30-day Review—Open for Public Comments” or by using the search function and entering either the title of the collection or the OMB Control Number 0648-0744.
                </P>
                <SIG>
                    <NAME>Sheleen Dumas,</NAME>
                    <TITLE>Department PRA Clearance Officer, Office of the Under Secretary for Economic Affairs, Commerce Department.</TITLE>
                </SIG>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10527 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3510-JE-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF COMMERCE</AGENCY>
                <SUBAGY>National Oceanic and Atmospheric Administration</SUBAGY>
                <SUBJECT>Agency Information Collection Activities; Submission to the Office of Management and Budget (OMB) for Review and Approval; Comment Request; Deep Seabed Mining Exploration Licenses</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>National Oceanic &amp; Atmospheric Administration (NOAA), Commerce.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of information collection, request for comment.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Department of Commerce, in accordance with the Paperwork Reduction Act of 1995 (PRA), invites the general public and other Federal agencies to comment on proposed, and continuing information collections, which helps us assess the impact of our information collection requirements and minimize the public's reporting burden. The purpose of this notice is to allow for 60 days of public comment preceding submission of the collection to OMB.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>To ensure consideration, comments regarding this proposed information collection must be received on or before July 15, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Interested persons are invited to submit written comments to Adrienne Thomas, NOAA PRA Officer, at 
                        <E T="03">NOAA.PRA@noaa.gov.</E>
                         Please reference OMB Control Number 0648-0145 in the subject line of your comments. Do not submit Confidential Business Information or otherwise sensitive or protected information.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Requests for additional information or specific questions related to collection activities should be directed to Kerry Kehoe, Federal Consistency Specialist, 1305 East-West Highway, 10th Floor, Silver Spring, MD 20910, 240-560-8518, 
                        <E T="03">Kerry.Kehoe@noaa.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">I. Abstract</HD>
                <P>This request is for the extension of the currently approved information collection. No changes have been made to the collection requirements. NOAA's regulations at 15 CFR part 970 govern the issuing and monitoring of exploration and production licenses under the Deep Seabed Hard Mineral Resources Act. The NOAA Office for Coastal Management is responsible for approving and administering licenses. Any persons seeking a license must submit certain information that allows NOAA to ensure the applicant meets the standards of the Act. Licensees are required to conduct monitoring and make reports, and they may request revisions, transfers, or extensions of licenses. Information required for the issuance and extension of licenses is provided to fulfill statutory requirements to ensure that license applicants have identified areas of interest for deep seabed hard mineral exploration and production; developed plans for those activities; have the financial resources available to conduct proposed activity; and have considered the effects of the activity on the natural and human environment. This information is used to determine whether licenses should be granted or extended.</P>
                <P>Exploration licenses and commercial recovery permits under the Deep Seabed Hard Mineral Resources Act are only for activities by U.S. citizens in international waters. No license or permit applications have been received since the early 1980s, and none are expected during this collection period. Two exploration licenses issued in the early 1980s are held by Lockheed Martin Corporation. The licenses are subject to annual reporting requirements and extension requests every five years. No at-sea exploration is authorized under the licenses without further authorization from NOAA.</P>
                <HD SOURCE="HD1">II. Method of Collection</HD>
                <P>Submission may be made by on paper or by electronic transmission.</P>
                <HD SOURCE="HD1">III. Data</HD>
                <P>
                    <E T="03">OMB Control Number:</E>
                     0648-0145.
                </P>
                <P>
                    <E T="03">Form Number(s):</E>
                     None.
                </P>
                <P>
                    <E T="03">Type of Review:</E>
                     Extension of a current information collection without change.
                </P>
                <P>
                    <E T="03">Affected Public:</E>
                     Businesses.
                </P>
                <P>
                    <E T="03">Estimated Number of Respondents:</E>
                     1.
                </P>
                <P>
                    <E T="03">Estimated Time per Response:</E>
                     Annual report: 20 hours; extension request: 250 hours.
                </P>
                <P>
                    <E T="03">Estimated Total Annual Burden Hours:</E>
                     20 hours. For those years in which an extension request must be made the estimated total annual burden is 270 hours.
                </P>
                <P>
                    <E T="03">Estimated Total Annual Cost to Public:</E>
                     $200 in record keeping/reporting costs.
                </P>
                <P>
                    <E T="03">Respondent's Obligation:</E>
                     Required to maintain or apply for licenses.
                </P>
                <P>
                    <E T="03">Legal Authority:</E>
                     30 U.S.C. 1441 et. seq.; 15 CFR part 970.
                </P>
                <HD SOURCE="HD1">IV. Request for Comments</HD>
                <P>We are soliciting public comments to permit the Department/Bureau to: (a) Evaluate whether the proposed information collection is necessary for the proper functions of the Department, including whether the information will have practical utility; (b) Evaluate the accuracy of our estimate of the time and cost burden for this proposed collection, including the validity of the methodology and assumptions used; (c) Evaluate ways to enhance the quality, utility, and clarity of the information to be collected; and (d) Minimize the reporting burden on those who are to respond, including the use of automated collection techniques or other forms of information technology.</P>
                <P>Comments that you submit in response to this notice are a matter of public record. We will include or summarize each comment in our request to OMB to approve this information collection requirement. Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you may ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.</P>
                <SIG>
                    <NAME>Sheleen Dumas,</NAME>
                    <TITLE>Department PRA Clearance Officer, Office of the Under Secretary for Economic Affairs, Commerce Department.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10535 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3510-08-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <PRTPAGE P="41946"/>
                <AGENCY TYPE="S">DEPARTMENT OF COMMERCE</AGENCY>
                <SUBAGY>National Oceanic and Atmospheric Administration</SUBAGY>
                <SUBJECT>Approval of a Boundary Expansion for the Narragansett Bay National Estuarine Research Reserve</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Office for Coastal Management, National Ocean Service, National Oceanic and Atmospheric Administration, Department of Commerce.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of approval; notice of availability.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>In accordance with the Coastal Zone Management Act and its implementing regulations, notice is hereby given that NOAA's Office for Coastal Management approves a 103-acre, one parcel boundary expansion for the Narragansett Bay National Estuarine Research Reserve in Prudence Island, Rhode Island. Pursuant to the National Environmental Policy Act, NOAA prepared a draft environmental assessment (draft EA) to analyze the effects of the requested expansion and solicited public comment on the draft EA. NOAA determined that the boundary expansion would not have significant environmental effects. Therefore, after considering the comments it received, NOAA issued a final environmental assessment and finding of no significant impact (FONSI).</P>
                </SUM>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        The final environmental assessment and FONSI can be downloaded or viewed at 
                        <E T="03">coast.noaa.gov/czm/compliance/.</E>
                         The documents are also available by sending a written request to the point of contact identified below (see 
                        <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                        ).
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Betsy Nicholson of NOAA's Office for Coastal Management, by email at 
                        <E T="03">betsy.nicholson@noaa.gov,</E>
                         phone at (339) 234-6965 (Google Voice), or mail at 55 Great Republic Drive, Gloucester, MA 01930.
                    </P>
                    <P>
                        <E T="03">Authority:</E>
                         16 U.S.C. 1451 
                        <E T="03">et seq.;</E>
                         42 U.S.C. 4321 
                        <E T="03">et seq.;</E>
                         15 CFR 921.33.
                    </P>
                    <SIG>
                        <NAME>Keelin S. Kuipers,</NAME>
                        <TITLE>Deputy Director, Office for Coastal Management, National Ocean Service, National Oceanic and Atmospheric Administration.</TITLE>
                    </SIG>
                </FURINF>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10462 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3510-08-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF COMMERCE</AGENCY>
                <SUBAGY>National Oceanic and Atmospheric Administration</SUBAGY>
                <SUBJECT>Agency Information Collection Activities; Submission to the Office of Management and Budget (OMB) for Review and Approval; Comment Request; Transshipment Requirements Under the WCPFC</SUBJECT>
                <P>
                    The Department of Commerce will submit the following information collection request to the Office of Management and Budget (OMB) for review and clearance in accordance with the Paperwork Reduction Act of 1995, on or after the date of publication of this notice. We invite the general public and other Federal agencies to comment on proposed, and continuing information collections, which helps us assess the impact of our information collection requirements and minimize the public's reporting burden. Public comments were previously requested via the 
                    <E T="04">Federal Register</E>
                     on February 2, 2024 during a 60-day comment period. This notice allows for an additional 30 days for public comments.
                </P>
                <P>
                    <E T="03">Agency:</E>
                     National Oceanic and Atmospheric Administration (NOAA), Commerce.
                </P>
                <P>
                    <E T="03">Title:</E>
                     Transshipment Requirements under the WCPFC.
                </P>
                <P>
                    <E T="03">OMB Control Number:</E>
                     0648-0649.
                </P>
                <P>
                    <E T="03">Form Number(s):</E>
                     None.
                </P>
                <P>
                    <E T="03">Type of Request:</E>
                     Regular submission; extension of a current information collection.
                </P>
                <P>
                    <E T="03">Number of Respondents:</E>
                     203.
                </P>
                <P>
                    <E T="03">Average Hours per Response:</E>
                     0-1 hour per collection item.
                </P>
                <P>
                    <E T="03">Total Annual Burden Hours:</E>
                     959 hours.
                </P>
                <P>
                    <E T="03">Needs and Uses:</E>
                     This request is for an extension of a currently approved information collection. National Marine Fisheries Service (NMFS) has issued regulations under authority of the Western and Central Pacific Fisheries Convention Implementation Act (WCPFCIA; 16 U.S.C. 6901 
                    <E T="03">et seq.</E>
                    ) to carry out the obligations of the United States under the Convention on the Conservation and Management of Highly Migratory Fish Stocks in the Western and Central Pacific Ocean (Convention), including implementing the decisions of the Commission for the Conservation and Management of Highly Migratory Fish Stocks in the Western and Central Pacific Ocean (WCPFC or Commission). The regulations include requirements for the owners and operators of U.S. vessels to: (1) complete and submit a Pacific Transshipment Declaration form for each transshipment that takes place in the area of application of the Convention (Convention Area) of highly migratory species caught in the Convention Area, (2) submit notice to the WCPFC Executive Director containing specific information at least 36 hours prior to each transshipment on the high seas in the Convention Area and within 12 hours after each emergency transshipment in the Convention Area, (3) in the event that a vessel anticipates a transshipment where an observer is required, provide notice to NMFS at least 72 hours before leaving port of the need for an observer, (4) complete and submit a U.S. Purse Seine Discard form within 48 hours after any discard, (5) submit daily purse seine fishing effort reports; (6) submit a notice to a contact designated by NMFS in the event of a serious illness, assault, harassment, intimidation or threat to a WCPFC observer; and (7) submit notice to obtain a WCPFC observer for a purse seine vessel departing from American Samoa.
                </P>
                <P>The information collected from these requirements is used by NOAA and the Commission to help ensure compliance with domestic laws and the Commission's conservation and management measures, and are necessary in order for the United States to satisfy its obligations under the Convention. There are no changes to this collection.</P>
                <P>
                    <E T="03">Affected Public:</E>
                     Business or other for-profit organizations; individuals or households.
                </P>
                <P>
                    <E T="03">Frequency:</E>
                     On Occasion.
                </P>
                <P>
                    <E T="03">Respondent's Obligation:</E>
                     Mandatory.
                </P>
                <P>
                    <E T="03">Legal Authority:</E>
                     WCPFCIA; 16 U.S.C. 6901 
                    <E T="03">et seq.</E>
                </P>
                <P>
                    This information collection request may be viewed at 
                    <E T="03">www.reginfo.gov.</E>
                     Follow the instructions to view the Department of Commerce collections currently under review by OMB.
                </P>
                <P>
                    Written comments and recommendations for the proposed information collection should be submitted within 30 days of the publication of this notice on the following website 
                    <E T="03">www.reginfo.gov/public/do/PRAMain.</E>
                     Find this particular information collection by selecting “Currently under 30-day Review—Open for Public Comments” or by using the search function and entering either the title of the collection or the OMB Control Number 0648-0649.
                </P>
                <SIG>
                    <NAME>Sheleen Dumas,</NAME>
                    <TITLE>Department PRA Clearance Officer, Office of the Under Secretary for Economic Affairs, Commerce Department.</TITLE>
                </SIG>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10534 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3510-22-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <PRTPAGE P="41947"/>
                <AGENCY TYPE="S">DEPARTMENT OF COMMERCE</AGENCY>
                <SUBAGY>National Oceanic and Atmospheric Administration</SUBAGY>
                <SUBJECT>Agency Information Collection Activities; Submission to the Office of Management and Budget (OMB) for Review and Approval; Comment Request; Fishery Capacity Reduction Program/Buyback Requests</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>National Oceanic &amp; Atmospheric Administration (NOAA), Commerce.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of information collection, request for comment.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Department of Commerce, in accordance with the Paperwork Reduction Act of 1995 (PRA), invites the general public and other Federal agencies to comment on proposed, and continuing information collections, which helps us assess the impact of our information collection requirements and minimize the public's reporting burden. The purpose of this notice is to allow for 60 days of public comment preceding submission of the collection to OMB.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>To ensure consideration, comments regarding this proposed information collection must be received on or before July 15, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Interested persons are invited to submit written comments to Adrienne Thomas, NOAA PRA Officer, at 
                        <E T="03">Adrienne.thomas@noaa.gov.</E>
                         Please reference OMB Control Number 0648-0376 in the subject line of your comments. Do not submit Confidential Business Information or otherwise sensitive or protected information.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Requests for additional information or specific questions related to collection activities should be directed to Moni Banerjee, Chief, Financial Services Division, NOAA National Marine Fisheries Service, (301) 427-8716 or 
                        <E T="03">moni.banerjee@noaa.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">I. Abstract</HD>
                <P>This request is for extension of a currently approved information collection. The Sustainable Fisheries Act (SFA) amended the Magnuson-Stevens Fishery Conservation and Management Act (MSA) to provide for voluntary reduction of excess fishing capacity through fishing capacity reduction (buyback) programs. Excess fishing capacity decreases fisheries earnings, complicates fishery management, and imperils fishery conservation. The statutory objective of a program is “to obtain the maximum sustained reduction in fishing capacity at the least cost and in a minimum period of time.” Buybacks pay fishermen either to: (1) Surrender their fishing permits; or (2) both surrender their permits and either scrap their fishing vessels or restrict vessel title to prevent fishing. Buybacks can involve either a Federal or State fishery. Buybacks can be funded via a long-term loan from the Federal government to the fishery (industry-funded buybacks), to be repaid by the industry by post-buyback landing fees, or funded from appropriations (non-industry funded) or other non-loan sources of funds. Programs involving industry-financed loans are authorized by section 1111 of title XI of the Merchant Marine Act, 1936.</P>
                <P>NOAA National Marine Fisheries Service (NMFS) established programs to reduce excess fishing capacity by paying fishermen to surrender their vessels/permits. The information collected by NMFS involves the submission of buyback requests by industry, submission of bids, referenda of fishery participants and reporting of collection of fees to repay buyback loans. For buybacks involving State-managed fisheries, the State may be involved in developing the buyback plan and complying with other information requirements. NMFS requests information from participating buyback participants to track repayments of the loans as well as ensure accurate management and monitoring of the loans. The fees for recordkeeping and reporting requirements at 50 CFR parts 600.1013 through 600.1017 form the basis for the collection of information.</P>
                <HD SOURCE="HD1">II. Method of Collection</HD>
                <P>Paper reports or electronic reports are required from buyback participants. Methods of submittal include mailing of paper reports, electronic submission via the internet.</P>
                <HD SOURCE="HD1">III. Data</HD>
                <P>
                    <E T="03">OMB Control Number:</E>
                     0648-0376.
                </P>
                <P>
                    <E T="03">Form Number:</E>
                     None.
                </P>
                <P>
                    <E T="03">Type of Review:</E>
                     Regular submission. [Extension of a current information collection.]
                </P>
                <P>
                    <E T="03">Affected Public:</E>
                     Individuals or households; business or other for-profit organizations.
                </P>
                <P>
                    <E T="03">Estimated Number of Respondents:</E>
                     200.
                </P>
                <P>
                    <E T="03">Estimated Time per Response:</E>
                     Implementation plan, 6,634 hours; referenda votes, bids, seller/buyer reports and annual fee collection reports, 4 hours each; completion of fish ticket, 10 minutes; monthly fee collection report, 2 hours; advising holder/owner of conflict with accepted bidders' representations, 1 hour; potentially 270 hours-state approval/review of plans.
                </P>
                <P>
                    <E T="03">Estimated Total Annual Burden Hours:</E>
                     15,838.
                </P>
                <P>
                    <E T="03">Estimated Total Annual Cost to Public:</E>
                     $1,596 in recordkeeping/filing costs.
                </P>
                <P>
                    <E T="03">Respondent's Obligation:</E>
                     Required to Obtain or Retain Benefits.
                </P>
                <P>
                    <E T="03">Legal Authority:</E>
                     Magnuson-Stevens Fishery Conservation and Management Reauthorization Act.
                </P>
                <HD SOURCE="HD1">IV. Request for Comments</HD>
                <P>We are soliciting public comments to permit the Department/Bureau to: (a) Evaluate whether the proposed information collection is necessary for the proper functions of the Department, including whether the information will have practical utility; (b) Evaluate the accuracy of our estimate of the time and cost burden for this proposed collection, including the validity of the methodology and assumptions used; (c) Evaluate ways to enhance the quality, utility, and clarity of the information to be collected; and (d) Minimize the reporting burden on those who are to respond, including the use of automated collection techniques or other forms of information technology.</P>
                <P>Comments that you submit in response to this notice are a matter of public record. We will include or summarize each comment in our request to OMB to approve this ICR. Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you may ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.</P>
                <SIG>
                    <NAME>Sheleen Dumas,</NAME>
                    <TITLE>Department PRA Clearance Officer, Office of the Under Secretary for Economic Affairs, Commerce Department.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10530 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3510-22-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <PRTPAGE P="41948"/>
                <AGENCY TYPE="S">DEPARTMENT OF COMMERCE</AGENCY>
                <SUBAGY>Patent and Trademark Office</SUBAGY>
                <SUBJECT>Agency Information Collection Activities; Submission to the Office of Management and Budget (OMB) for Review and Approval; Comment Request; Patent Prosecution Highway (PPH) Program</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Patent and Trademark Office, Department of Commerce.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of information collection; request for comment.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The United States Patent and Trademark Office (USPTO), as required by the Paperwork Reduction Act of 1995, invites comments on the extension and revision of an existing information collection: 0651-0058 (Patent Prosecution Highway (PPH) Program). The purpose of this notice is to allow 60 days for public comment preceding submission of the information collection to OMB.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>To ensure consideration, comments regarding this information collection must be received on or before July 15, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>Interested persons are invited to submit written comments by any of the following methods. Do not submit Confidential Business Information or otherwise sensitive or protected information.</P>
                    <P>
                        • 
                        <E T="03">Email: InformationCollection@uspto.gov.</E>
                         Include “0651-0058 comment” in the subject line of the message.
                    </P>
                    <P>
                        • 
                        <E T="03">Federal eRulemaking Portal: http://www.regulations.gov.</E>
                    </P>
                    <P>
                        • 
                        <E T="03">Mail:</E>
                         Justin Isaac, Office of the Chief Administrative Officer, United States Patent and Trademark Office, P.O. Box 1450, Alexandria, VA 22313-1450.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Requests for additional information should be directed to Jeffrey West, Senior Legal Advisor, United States Patent and Trademark Office, P.O. Box 1450, Alexandria, VA 22313-1450; by telephone at 571-272-2226; or by email at 
                        <E T="03">jeffrey.west@uspto.gov</E>
                         with “0651-0058 comment” in the subject line. Additional information about this information collection is also available at 
                        <E T="03">http://www.reginfo.gov</E>
                         under “Information Collection Review.”
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">I. Abstract</HD>
                <P>The Patent Prosecution Highway (PPH) is a framework in which an application whose claims have been determined to be patentable by the Office of Earlier Examination (OEE) is eligible to go through an accelerated examination in an Office of Later Examination (OLE) with a simple procedure upon an applicant's request. By leveraging the search and examination work product of the OEE, PPH programs (1) deliver lower prosecution costs, (2) support applicants in their efforts to obtain stable patent rights efficiently around the world, and (3) reduce the search and examination burden, while improving the examination quality, of participating patent offices.</P>
                <P>Initially, the PPH programs were limited to the utilization of search and examination results of national applications between cross filings under the Paris Convention. Later, the potential of the PPH was greatly expanded by Patent Cooperation Treaty (PCT)-PPH programs, which permit participating patent offices to draw upon the positive results of the PCT work product from another participating office. PCT-PPH programs use international written opinions and international preliminary examination reports developed within the framework of the PCT, thereby making the PPH available to a larger number of applicants. Information collected for the PCT is approved under the USPTO information collection 0651-0021 (Patent Cooperation Treaty).</P>
                <P>More recently, the USPTO and several other offices acted to consolidate and replace existing PPH programs, with the goal of streamlining the PPH process for both offices and applicants. To that end, the USPTO and other offices established the Global PPH pilot program and the IP5 PPH pilot program. Both the Global PPH and IP5 PPH pilot programs are running concurrently and are substantially identical, differing only with regard to their respective participating offices. The USPTO participates in both the Global PPH pilot program and the IP5 PPH pilot program. For USPTO applications, the Global PPH and IP5 PPH pilot programs supersede any prior PPH program between the USPTO and each Global PPH and IP5 PPH participating office. Any existing PPH programs between the USPTO and offices that are not participating in either the Global PPH pilot program or the IP5 PPH pilot program remain in effect.</P>
                <P>This information collection covers data gathered through the Request for Participation in the Patent Prosecution Highway (PPH) Pilot Program, which the public uses to request an accelerated examination within the PPH provisions.</P>
                <HD SOURCE="HD1">II. Method of Collection</HD>
                <P>Information in this information collection must be submitted electronically.</P>
                <HD SOURCE="HD1">III. Data</HD>
                <P>
                    <E T="03">OMB Control Number:</E>
                     0651-0058.
                </P>
                <P>
                    <E T="03">Forms:</E>
                     (SB = Specimen Book)
                </P>
                <FP SOURCE="FP-1">• PTO/SB/20BR (Request for Participation in the Patent Prosecution Highway (PPH) Pilot Program Between the Brazilian National Institute of Industrial Property (INPI) and the USPTO)</FP>
                <FP SOURCE="FP-1">• PTO/SB/20CZ (Request for Participation in the Patent Prosecution Highway (PPH) Pilot Program Between the Industrial Property Office of the Czech Republic (IPOCZ) and the USPTO)</FP>
                <FP SOURCE="FP-1">• PTO/SB/20FR (Request for Participation in the Patent Prosecution Highway (PPH) Pilot Program Between the National Institute of Industrial Property of France (INPI) and the USPTO)</FP>
                <FP SOURCE="FP-1">• PTO/SB/20GLBL (Request for Participation in the Global/IP5 Patent Prosecution Highway (PPH) Pilot Program in the USPTO)</FP>
                <FP SOURCE="FP-1">• PTO/SB/20MA (Request for Participation in the Patent Prosecution Highway (PPH) Pilot Program Between the Moroccan Office of Industrial and Commercial Property (OMPIC) and the USPTO)</FP>
                <FP SOURCE="FP-1">• PTO/SB/20MX (Request for Participation in the Patent Prosecution Highway (PPH) Pilot Program Between the Mexican Institute of Industrial Property (IMPI) and the USPTO)</FP>
                <FP SOURCE="FP-1">• PTO/SB/20MY (Request for Participation in the Patent Prosecution Highway (PPH) Pilot Program Between the Intellectual Property Corporation of Malaysia (MYIPO) and the USPTO)</FP>
                <FP SOURCE="FP-1">• PTO/SB/20NI (Request for Participation in the Patent Prosecution Highway (PPH) Pilot Program Between the Nicaraguan Registry of Intellectual Property (NRIP) and the USPTO)</FP>
                <FP SOURCE="FP-1">• PTO/SB/20PH (Request for Participation in the Patent Prosecution Highway (PPH) Pilot Program Between the Intellectual Property Office of the Philippines (IPOPH) and the USPTO)</FP>
                <FP SOURCE="FP-1">• PTO/SB/20RO (Request for Participation in the Patent Prosecution Highway (PPH) Pilot Program Between the Romanian State Office for Inventions and Trademarks (OSIM) and the USPTO)</FP>
                <FP SOURCE="FP-1">
                    • PTO/SB/20SA (Request for Participation in the Patent 
                    <PRTPAGE P="41949"/>
                    Prosecution Highway (PPH) Pilot Program Between the Saudi Authority for Intellectual Property of the Kingdom of Saudi Arabia (SAIP) and the USPTO)
                </FP>
                <FP SOURCE="FP-1">• PTO/SB/20TW (Request for Participation in the Patent Prosecution Highway (PPH) Pilot Program Between the Taiwan Intellectual Property Office (TIPO) and the USPTO)</FP>
                <P>
                    <E T="03">Type of Review:</E>
                     Extension and revision of a currently approved information collection.
                </P>
                <P>
                    <E T="03">Affected Public:</E>
                     Private sector.
                </P>
                <P>
                    <E T="03">Respondent's Obligation:</E>
                     Required to obtain or retain benefits.
                </P>
                <P>
                    <E T="03">Estimated Number of Annual Respondents:</E>
                     8,585 respondents.
                </P>
                <P>
                    <E T="03">Estimated Number of Annual Responses:</E>
                     8,585 responses.
                </P>
                <P>
                    <E T="03">Frequency:</E>
                     On occasion.
                </P>
                <P>
                    <E T="03">Estimated Time per Response:</E>
                     The USPTO estimates that the responses in this information collection will take the public approximately 2 hours to complete. This includes the time to gather the necessary information, create the document, and submit the completed request to the USPTO.
                </P>
                <P>
                    <E T="03">Estimated Total Annual Respondent Burden Hours:</E>
                     17,170 hours.
                </P>
                <P>
                    <E T="03">Estimated Total Annual Respondent Hourly Cost Burden:</E>
                     $7,674,990.
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>1</SU>
                         2023 Report of the Economic Survey, published by the Committee on Economics of Legal Practice of the American Intellectual Property Law Association (AIPLA); pg. F-41. The USPTO uses the average billing rate for intellectual property work in all firms which is $447 per hour (
                        <E T="03">https://www.aipla.org/home/news-publications/economic-survey</E>
                        ).
                    </P>
                </FTNT>
                <GPOTABLE COLS="9" OPTS="L2(,0,),p7,7/8,i1" CDEF="xs40,r50,12,13,12,12,12,12,12">
                    <TTITLE>Table 1—Total Burden Hours and Hourly Costs to Private Sector Respondents</TTITLE>
                    <BOXHD>
                        <CHED H="1">Item No.</CHED>
                        <CHED H="1">Item</CHED>
                        <CHED H="1">
                            Estimated
                            <LI>annual</LI>
                            <LI>respondents </LI>
                        </CHED>
                        <CHED H="1">
                            Responses per
                            <LI>respondent </LI>
                        </CHED>
                        <CHED H="1">
                            Estimated
                            <LI>annual</LI>
                            <LI>responses </LI>
                        </CHED>
                        <CHED H="1">
                            Estimated
                            <LI>time for</LI>
                            <LI>response</LI>
                            <LI>(hours) </LI>
                        </CHED>
                        <CHED H="1">
                            Estimated
                            <LI>burden</LI>
                            <LI>(hour/year) </LI>
                        </CHED>
                        <CHED H="1">
                            Rate 
                            <SU>1</SU>
                            <LI>($/hour) </LI>
                        </CHED>
                        <CHED H="1">
                            Estimated
                            <LI>annual</LI>
                            <LI>respondent</LI>
                            <LI>cost burden</LI>
                        </CHED>
                    </BOXHD>
                    <ROW RUL="s">
                        <ENT I="25"> </ENT>
                        <ENT> </ENT>
                        <ENT>(a)</ENT>
                        <ENT>(b)</ENT>
                        <ENT>(a) × (b) = (c)</ENT>
                        <ENT>(d)</ENT>
                        <ENT>(c) × (d) = (e)</ENT>
                        <ENT>(f)</ENT>
                        <ENT>(e) × (f) = (g)</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">1</ENT>
                        <ENT>Request for Participation in the Global/IP5 PPH Pilot Program in the USPTO</ENT>
                        <ENT>8,500</ENT>
                        <ENT>1</ENT>
                        <ENT>8,500</ENT>
                        <ENT>2</ENT>
                        <ENT>17,000</ENT>
                        <ENT>$447</ENT>
                        <ENT>$7,599,000</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">2</ENT>
                        <ENT>Request for Participation in the PPH Pilot Program Between the Brazilian National Institute of Industrial Property (INPI) and the USPTO</ENT>
                        <ENT>4</ENT>
                        <ENT>1</ENT>
                        <ENT>4</ENT>
                        <ENT>2</ENT>
                        <ENT>8</ENT>
                        <ENT>447</ENT>
                        <ENT>3,576</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">3</ENT>
                        <ENT>Request for Participation in the PPH Pilot Program Between the Industrial Property Office of the Czech Republic (IPOCZ) and the USPTO</ENT>
                        <ENT>1</ENT>
                        <ENT>1</ENT>
                        <ENT>1</ENT>
                        <ENT>2</ENT>
                        <ENT>2</ENT>
                        <ENT>447</ENT>
                        <ENT>894</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">4</ENT>
                        <ENT>Request for Participation in the PPH Pilot Program Between National Institute of Industrial Property of France (INPI) and the USPTO</ENT>
                        <ENT>15</ENT>
                        <ENT>1</ENT>
                        <ENT>15</ENT>
                        <ENT>2</ENT>
                        <ENT>30</ENT>
                        <ENT>447</ENT>
                        <ENT>13,410</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">5</ENT>
                        <ENT>Request for Participation in the PPH Pilot Program Between the Moroccan Office of Industrial and Commercial Property (OMPIC) and the USPTO</ENT>
                        <ENT>1</ENT>
                        <ENT>1</ENT>
                        <ENT>1</ENT>
                        <ENT>2</ENT>
                        <ENT>2</ENT>
                        <ENT>447</ENT>
                        <ENT>894</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">6</ENT>
                        <ENT>Request for Participation in the PPH Pilot Program Between the Mexican Institute of Industrial Property (IMPI) and the USPTO</ENT>
                        <ENT>2</ENT>
                        <ENT>1</ENT>
                        <ENT>2</ENT>
                        <ENT>2</ENT>
                        <ENT>4</ENT>
                        <ENT>447</ENT>
                        <ENT>1,788</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">7</ENT>
                        <ENT>Request for Participation in the PPH Pilot Program Between the Intellectual Property Corporation of Malaysia (MYIPO) and the USPTO)</ENT>
                        <ENT>1</ENT>
                        <ENT>1</ENT>
                        <ENT>1</ENT>
                        <ENT>2</ENT>
                        <ENT>2</ENT>
                        <ENT>447</ENT>
                        <ENT>894</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">8</ENT>
                        <ENT>Request for Participation in the PPH Pilot Program Between the Nicaraguan Registry of Intellectual Property (NRIP) and the USPTO</ENT>
                        <ENT>1</ENT>
                        <ENT>1</ENT>
                        <ENT>1</ENT>
                        <ENT>2</ENT>
                        <ENT>2</ENT>
                        <ENT>447</ENT>
                        <ENT>894</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">9</ENT>
                        <ENT>Request for Participation in the PPH Pilot Program Between the Intellectual Property Office of the Philippines (IPOPH) and the USPTO</ENT>
                        <ENT>1</ENT>
                        <ENT>1</ENT>
                        <ENT>1</ENT>
                        <ENT>2</ENT>
                        <ENT>2</ENT>
                        <ENT>447</ENT>
                        <ENT>894</ENT>
                    </ROW>
                    <ROW>
                        <PRTPAGE P="41950"/>
                        <ENT I="01">10</ENT>
                        <ENT>Request for Participation in the PPH Pilot Program Between the Romanian State Office for Inventions and Trademarks (OSIM) and the USPTO)</ENT>
                        <ENT>1</ENT>
                        <ENT>1</ENT>
                        <ENT>1</ENT>
                        <ENT>2</ENT>
                        <ENT>2</ENT>
                        <ENT>447</ENT>
                        <ENT>894</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">11</ENT>
                        <ENT>Request for Participation in the PPH Pilot Program Between the Saudi Authority for Intellectual Property of the Kingdom of Saudi Arabia (SAIP) and the USPTO</ENT>
                        <ENT>1</ENT>
                        <ENT>1</ENT>
                        <ENT>1</ENT>
                        <ENT>2</ENT>
                        <ENT>2</ENT>
                        <ENT>447</ENT>
                        <ENT>894</ENT>
                    </ROW>
                    <ROW RUL="n,n,s">
                        <ENT I="01">12</ENT>
                        <ENT>Request for Participation in the PPH Pilot Program Between the Taiwan Intellectual Property Office (TIPO) and the USPTO</ENT>
                        <ENT>57</ENT>
                        <ENT>1</ENT>
                        <ENT>57</ENT>
                        <ENT>2</ENT>
                        <ENT>114</ENT>
                        <ENT>447</ENT>
                        <ENT>50,958</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="22"> </ENT>
                        <ENT>Totals</ENT>
                        <ENT>8,585</ENT>
                        <ENT/>
                        <ENT>8,585</ENT>
                        <ENT/>
                        <ENT>17,170</ENT>
                        <ENT/>
                        <ENT>7,674,990</ENT>
                    </ROW>
                </GPOTABLE>
                <P>
                    <E T="03">Estimated Total Annual Respondent Non-hourly Cost Burden:</E>
                     $0. There are no capital start-up costs, maintenance costs, recordkeeping costs, filing fees, or postage costs associated with this information collection.
                </P>
                <HD SOURCE="HD1">IV. Request for Comments</HD>
                <P>The USPTO is soliciting public comments to:</P>
                <P>(a) Evaluate whether the collection of information is necessary for the proper performance of the functions of the Agency, including whether the information will have practical utility;</P>
                <P>(b) Evaluate the accuracy of the Agency's estimate of the burden of the collection of information, including the validity of the methodology and assumptions used;</P>
                <P>(c) Enhance the quality, utility, and clarity of the information to be collected; and</P>
                <P>
                    (d) Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, 
                    <E T="03">e.g.,</E>
                     permitting electronic submission of responses.
                </P>
                <P>All comments submitted in response to this notice are a matter of public record. The USPTO will include or summarize each comment in the request to OMB to approve this information collection. Before including an address, phone number, email address, or other personally identifiable information (PII) in a comment, be aware that the entire comment—including PII—may be made publicly available at any time. While you may ask in your comment to withhold PII from public view, the USPTO cannot guarantee that it will be able to do so.</P>
                <SIG>
                    <NAME>Justin Isaac,</NAME>
                    <TITLE>Information Collections Officer, Office of the Chief Administrative Officer, United States Patent and Trademark Office. </TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10476 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3510-16-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF DEFENSE</AGENCY>
                <SUBAGY>Office of the Secretary</SUBAGY>
                <DEPDOC>[Transmittal No. 22-14]</DEPDOC>
                <SUBJECT>Arms Sales Notification</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Defense Security Cooperation Agency, Department of Defense (DoD).</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Arms sales notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The DoD is publishing the unclassified text of an arms sales notification.</P>
                </SUM>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Neil Hedlund at 
                        <E T="03">neil.g.hedlund.civ@mail.mil</E>
                         or (703) 697-9214.
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>This 36(b)(1) arms sales notification is published to fulfill the requirements of section 155 of Public Law 104-164 dated July 21, 1996. The following is a copy of a letter to the Speaker of the House of Representatives, Transmittal 22-14 with attached Policy Justification and Sensitivity of Technology.</P>
                <SIG>
                    <DATED>Dated: May 8, 2024.</DATED>
                    <NAME>Aaron T. Siegel,</NAME>
                    <TITLE>Alternate OSD Federal Register Liaison Officer, Department of Defense.</TITLE>
                </SIG>
                <BILCOD>BILLING CODE 6001-FR-P</BILCOD>
                <GPH SPAN="3" DEEP="564">
                    <PRTPAGE P="41951"/>
                    <GID>EN14MY24.114</GID>
                </GPH>
                <BILCOD>BILLING CODE 6001-FR-C</BILCOD>
                <HD SOURCE="HD3">Transmittal No. 22-14</HD>
                <HD SOURCE="HD3">Notice of Proposed Issuance of Letter of Offer Pursuant to Section 36(b)(1) of the Arms Export Control Act, as amended</HD>
                <P>
                    (i) 
                    <E T="03">Prospective Purchaser:</E>
                     Government of Bulgaria
                </P>
                <P>
                    (ii) 
                    <E T="03">Total Estimated Value:</E>
                </P>
                <GPOTABLE COLS="2" OPTS="L0,tp0,p1,8/9,g1,t1,i1" CDEF="s30,14">
                    <TTITLE> </TTITLE>
                    <BOXHD>
                        <CHED H="1"> </CHED>
                        <CHED H="1"> </CHED>
                    </BOXHD>
                    <ROW>
                        <ENT I="01">Major Defense Equipment *</ENT>
                        <ENT>$0.978 billion</ENT>
                    </ROW>
                    <ROW RUL="n,s">
                        <ENT I="01">Other</ENT>
                        <ENT>$0.695 billion</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">TOTAL</ENT>
                        <ENT>$1.673 billion</ENT>
                    </ROW>
                </GPOTABLE>
                <P>Funding Source: National Funds</P>
                <P>
                    (iii) 
                    <E T="03">Description and Quantity or Quantities of Articles or Services under Consideration for Purchase:</E>
                </P>
                <FP SOURCE="FP-2">
                    <E T="03">Major Defense Equipment (MDE):</E>
                </FP>
                <FP SOURCE="FP1-2">Four (4) F-16 C Block 70 Aircraft</FP>
                <FP SOURCE="FP1-2">Four (4) F-16 D Block 70 Aircraft</FP>
                <FP SOURCE="FP1-2">Eleven (11) F100-GE-129D Engines (8 installed, 3 spares)</FP>
                <FP SOURCE="FP1-2">Eleven (11) Improved Programmable Display Generators (iPDG) (8 installed, 3 spares)</FP>
                <FP SOURCE="FP1-2">
                    Eleven (11) AN/APG-83 Active Electronically Scanned Array (AESA) Scalable Agile Beam Radars 
                    <PRTPAGE P="41952"/>
                    (SABR) (8 installed, 3 spares)
                </FP>
                <FP SOURCE="FP1-2">Eleven (11) Modular Mission Computers (MMC) 7000AH (8 installed, 3 spares)</FP>
                <FP SOURCE="FP1-2">Eleven (11) LN-260 or equivalent Embedded Global Positioning System (GPS) Inertial Navigation Systems (INS) (EGI) with Selective Availability Anti-Spoofing Module (SAASM) and Precise Positioning Service (PPS) (8 installed, 3 spares)</FP>
                <FP SOURCE="FP1-2">Nineteen (19) Advanced Medium Range Air-to-Air Missile (AMRAAM) AIM-120C-7/C-8 or equivalent Missiles</FP>
                <FP SOURCE="FP1-2">Two (2) AMRAAM Guidance Sections</FP>
                <FP SOURCE="FP1-2">Forty-eight (48) LAU-129A Launchers (40 installed, 8 spares)</FP>
                <FP SOURCE="FP1-2">Twenty-eight (28) GBU-39/B Small Diameter Bombs (SDBs)</FP>
                <FP SOURCE="FP1-2">Two (2) SDB Guided Test Vehicles (GTVs)</FP>
                <FP SOURCE="FP1-2">Eleven (11) M61A1 Vulcan Cannons (8 installed, 3 spares)</FP>
                <FP SOURCE="FP1-2">Four (4) AN/AAQ-33 Sniper Advanced Targeting Pods (ATPs)</FP>
                <FP SOURCE="FP1-2">Twelve (12) Multifunctional Information Distribution System with Joint Tactical Radio Systems (MIDS-JTRS) (aircraft terminals and ground station terminals) (10 installed, 2 spares)</FP>
                <FP SOURCE="FP1-2">Twenty (20) AIM-9X Block II Missiles</FP>
                <FP SOURCE="FP1-2">Eight (8) AIM-9X Block II Captive Air Training Missiles (CATMs)</FP>
                <FP SOURCE="FP1-2">Four (4) AIM-9X Block II Tactical Guidance Units</FP>
                <FP SOURCE="FP1-2">Four (4) AIM-9X Block II CATM Guidance Units</FP>
                <FP SOURCE="FP1-2">Twenty-four (24) FMU-139 or FMU-152 Fuze Systems</FP>
                <FP SOURCE="FP1-2">Twelve (12) KMU-572 Joint Direct Attack Munition Tail Kits for 500LB GBU-38 or Laser JDAM GBU-54</FP>
                <FP SOURCE="FP1-2">Twelve (12) MXU-650 Air Foil Groups (AFGs) for Enhanced Paveway II EGBU-49</FP>
                <FP SOURCE="FP1-2">Twelve (12) MAU-210 Enhanced Computer Control Groups (ECCGs) for EPII EGBU-49</FP>
                <FP SOURCE="FP1-2">Twenty-four (24) MK-82 or BLU-111 or equivalent Bomb Bodies</FP>
                <FP SOURCE="FP1-2">Six (6) MK-82 Inert Bombs</FP>
                <FP SOURCE="FP1-2">Two (2) GBU-39 SDB I Practice Bombs</FP>
                <FP SOURCE="FP-2">
                    <E T="03">Non-MDE:</E>
                </FP>
                <FP SOURCE="FP1-2">Also included are AN/ARC-238 radios; AN/APX-126 or equivalent Advanced Identification Friend or Foe (AIFF) with Combined Interrogator Transponders (CIT); Joint Helmet Mounted Cueing System II (JHMCS II) or Scorpion Hybrid Optical-based Inertial Tacker (HObIT) helmet mounted displays; AN/ALQ-254 Viper Shield or equivalent Electronic Warfare (EW) systems; AN/ALE-47 Countermeasure Dispenser Systems (CMDS), KY-58M Cryptographic Devices, KIV-78 Cryptographic Devices, and Simple Key Loaders (SKLs); Joint Mission Planning Systems (JMPS) or equivalent; AIM-120 Captive Air Training Missiles (CATM); PGU-28 High Explosive Incendiary (HEI) ammunition; PGU-27 training rounds (non HEI); ARD-446 impulse cartridges; ARD-863 impulse cartridges; BBU-36/B impulse cartridges; BBU-35/B impulse cartridges; MK-124 smoke flares; MJU-7/B flare cartridges L463 or MJU-53 or equivalent; Common Munitions Built-in-Test (BIT) Reprogramming Equipment (CMBRE); ADU-890 adapter for CMBRE; ADU-891 adapter for CMBRE; Night Vision Devices (NVD); NVD Spare Image Intensifier Tubes; Remote Operated Video Enhanced Receiver (ROVER) 6i units; Tactical Network ROVER Kit; DSU-38 laser sensors for GBU-54; Cartridge Actuated Device/Propellant Actuated Devices (CADs/PADs); GBU-39 tactical training rounds; BRU-57 bomb racks; BRU-61 bomb racks; MAU-12 bomb racks and TER-9A triple ejection racks; other chaff and flare, ammunition, and pylons; launcher adaptors and weapons interfaces; fuel tanks and attached hardware; travel pods; aircraft and weapons integration, test, and support equipment; electronic warfare database and mission data file development; precision measurement and calibration laboratory equipment; secure communications; cryptographic equipment; precision navigation equipment; aircraft and personnel support and test equipment; spare and repair parts; repair and return services; maps, publications, and technical documentation; studies and surveys; classified/unclassified software and software support; personnel training and training equipment; facilities and facility management, design and/or construction services; U.S. Government and contractor engineering, technical and logistics support services; and other related elements of logistical and program support.</FP>
                <P>
                    (iv) 
                    <E T="03">Military Department:</E>
                     Air Force (BU-D-SAD) and Navy (BU-P-AAH, BU-P-LBC)
                </P>
                <P>
                    (v) 
                    <E T="03">Prior Related Cases, if any:</E>
                     BU-D-SAB
                </P>
                <P>
                    (vi) 
                    <E T="03">Sales Commission, Fee, etc., Paid, Offered, or Agreed to be Paid:</E>
                     None known at this time
                </P>
                <P>
                    (vii) 
                    <E T="03">Sensitivity of Technology Contained in the Defense Article or Defense Services Proposed to be Sold:</E>
                     See Attached Annex
                </P>
                <P>
                    (viii) 
                    <E T="03">Date Report Delivered to Congress:</E>
                     April 4, 2022
                </P>
                <P>* As defined in Section 47(6) of the Arms Export Control Act.</P>
                <HD SOURCE="HD2">POLICY JUSTIFICATION</HD>
                <HD SOURCE="HD2">Bulgaria—F-16 C/D Block 70 Aircraft</HD>
                <P>
                    The Government of Bulgaria has requested to buy four (4) F-16 C Block 70 aircraft; four (4) F-16 D Block 70 aircraft; eleven (11) F100-GE-129D engines (8 installed, 3 spares); eleven (11) Improved Programmable Display Generators (iPDG) (8 installed, 3 spares); eleven (11) AN/APG-83 Active Electronically Scanned Array (AESA) Scalable Agile Beam Radars (SABR) (8 installed, 3 spares); eleven (11) Modular Mission Computers (MMC) 7000AH (8 installed, 3 spares); eleven (11) LN-260 or equivalent Embedded Global Positioning System (GPS) Inertial Navigation Systems (INS) (EGI) with Selective Availability Anti-Spoofing Module (SAASM) and Precise Positioning Service (PPS) (8 installed, 3 spares); nineteen (19) Advanced Medium Range Air-to-Air Missile (AMRAAM) AIM-120C-7/C-8 or equivalent missiles; two (2) AMRAAM Guidance Sections; forty-eight (48) LAU-129A launchers (40 installed, 8 spares); twenty-eight (28) GBU-39/B Small Diameter Bombs (SDBs); two (2) SDB Guided Test Vehicles (GTVs); eleven (11) M61A1 Vulcan Cannons (8 installed, 3 spares); four (4) AN/AAQ-33 Sniper Advanced Targeting Pods (ATPs); twelve (12) Multifunctional Information Distribution System with Joint Tactical Radio Systems (MIDS-JTRS) (aircraft terminals and ground station terminals) (10 installed, 2 spares); twenty (20) AIM-9X Block II missiles; eight (8) AIM-9X Block II Captive Air Training Missiles (CATMs); four (4) AIM-9X Block II Tactical Guidance Units; four (4) AIM-9X Block II CATM Guidance Units; twenty-four (24) FMU-139 or FMU-152 fuze systems; twelve (12) KMU-572 Joint Direct Attack Munition (JDAM) Tail Kits for 500LB GBU-38 or Laser JDAM GBU-54; twelve (12) MXU-650 Air Foil Groups (AFGs) for Enhanced Paveway II EGBU-49; twelve (12) MAU-210 Enhanced Computer Control Groups (ECCGs) for EPII EGBU-49; twenty-four (24) MK-82 or BLU-111 or equivalent Bomb Bodies; six (6) MK-82 Inert Bombs; and two (2) GBU-39 SDB I 
                    <PRTPAGE P="41953"/>
                    Practice Bombs. Also included are AN/ARC-238 radios; AN/APX-126 or equivalent Advanced Identification Friend or Foe (AIFF) with Combined Interrogator Transponders (CIT); Joint Helmet Mounted Cueing System II (JHMCS II) or Scorpion Hybrid Optical-based Inertial Tacker (HObIT) helmet mounted displays; AN/ALQ-254 Viper Shield or equivalent Electronic Warfare (EW) systems; AN/ALE-47 Countermeasure Dispenser Systems (CMDS), KY-58M Cryptographic Devices, KIV-78 Cryptographic Devices, and Simple Key Loaders (SKLs); Joint Mission Planning Systems (JMPS) or equivalent; AIM-120 Captive Air Training Missiles (CATM); PGU-28 High Explosive Incendiary (HEI) ammunition; PGU-27 training rounds (non HEI); ARD-446 impulse cartridges; ARD-863 impulse cartridges; BBU-36/B impulse cartridges; BBU-35/B impulse cartridges; MK-124 smoke flares; MJU-7/B flare cartridges L463 or MJU-53 or equivalent; Common Munitions Built-in-Test (BIT) Reprogramming Equipment (CMBRE); ADU-890 adapter for CMBRE; ADU-891 adapter for CMBRE; Night Vision Devices (NVD); NVD Spare Image Intensifier Tubes; Remote Operated Video Enhanced Receiver (ROVER) 6i units; Tactical Network ROVER Kit; DSU-38 laser sensors for GBU-54; Cartridge Actuated Device/Propellant Actuated Devices (CADs/PADs); GBU-39 tactical training rounds; BRU-57 bomb racks; BRU-61 bomb racks; MAU-12 bomb racks and TER-9A triple ejection racks; other chaff and flare, ammunition, and pylons; launcher adaptors and weapons interfaces; fuel tanks and attached hardware; travel pods; aircraft and weapons integration, test, and support equipment; electronic warfare database and mission data file development; precision measurement and calibration laboratory equipment; secure communications; cryptographic equipment; precision navigation equipment; aircraft and personnel support and test equipment; spare and repair parts; repair and return services; maps, publications, and technical documentation; studies and surveys; classified/unclassified software and software support; personnel training and training equipment; facilities and facility management, design and/or construction services; U.S. Government and contractor engineering, technical and logistics support services; and other related elements of logistical and program support. The estimated total cost is $1.673 billion.
                </P>
                <P>This proposed sale will support the foreign policy and national security objectives of the United States by helping to improve the security of a NATO ally that is a force for political stability and economic progress in Europe.</P>
                <P>The proposed sale will improve Bulgaria's capability to meet current and future threats by enabling the Bulgarian Air Force to deploy modern fighter aircraft routinely in the Black Sea region. The acquisition of these aircraft would provide Bulgaria a NATO interoperable platform and allow the Bulgarian Air Force to operate more frequently alongside other regional F-16 operators, promoting common doctrine and operations. Bulgaria has shown a commitment to modernizing its armed forces and will have no difficulty absorbing these aircraft and services into its armed forces.</P>
                <P>The proposed sale of this equipment and support will not alter the basic military balance in the region.</P>
                <P>The principal contractor will be Lockheed Martin, Greenville, South Carolina. There are no known offset agreements proposed in connection with this potential sale.</P>
                <P>Implementation of this proposed sale will require the assignment of U.S. contractor representatives (fewer than 20) to Bulgaria for a duration of thirty-six (36) months to support secure storage requirements of critically controlled assets and provide on-site contractor logistics support.</P>
                <P>There will be no adverse impact on U.S. defense readiness as a result of this proposed sale.</P>
                <HD SOURCE="HD3">Transmittal No. 22-14</HD>
                <HD SOURCE="HD3">Notice of Proposed Issuance of Letter of Offer Pursuant to Section 36(b)(1) of the Arms Export Control Act</HD>
                <HD SOURCE="HD3">Annex</HD>
                <HD SOURCE="HD3">Item No. vii</HD>
                <P>
                    (vii) 
                    <E T="03">Sensitivity of Technology:</E>
                </P>
                <P>1. The F-16 Block 70 weapon system is a fourth generation single-engine supersonic all-weather multirole fighter aircraft and features advanced avionics and systems. It contains the General Electric F110-129D engine, AN/APG-83 radar, digital flight control system, embedded internal global navigation system, Joint Helmet Mounted Cueing Systems (JHMCS) II or Scorpion Hybrid Optical-based Inertial Tracker (HObIT) with Night Vision Device (NVD) compatibility, internal and external Electronic Warfare (EW) equipment, Advanced IFF, LINK-16 datalink, operational flight trainer, and software computer systems.</P>
                <P>2. The General Electric F110-129 engine is an afterburning turbofan jet engine that powers the F-16.</P>
                <P>3. The Improved Programmable Display Generator (iPDG) and color multifunction displays utilize ruggedized commercial liquid crystal display technology that is designed to withstand the harsh environment found in modern fighter cockpits. The display generator is the fifth generation graphics processor for the F-16. Through the use of state-of-the-art microprocessors and graphics engines, it provided orders of magnitude increases in throughput, memory, and graphics capabilities.</P>
                <P>
                    4. The Scalable Agile Beam Radar (SABR) APG-83 is an Active Electronically Scanned Array (AESA) radar upgrade for the F-16. It includes higher processor power, higher transmission power, more sensitive receiver electronics, and Synthetic Aperture Radar (SAR), which creates higher-resolution ground maps from a greater distance than existing mechanically scanned array radars (
                    <E T="03">e.g.,</E>
                     APG-68). The upgrade features an increase in detection range of air targets, increases in processing speed and memory, as well as significant improvements in all modes.
                </P>
                <P>5. The Modular Mission Computer (MMC) 7000AH is the central aircraft computer of the F-16. It serves as the hub for all aircraft subsystems and avionics data transfer.</P>
                <P>6. The Embedded GPS-INS (EGI) with Selective Availability Anti-Spoofing Module (SAASM) is a self-contained navigation system that provides the following: acceleration, velocity, position, attitude, platform azimuth, magnetic and true heading, altitude, body angular rates, time tags, and coordinated universal time (UTC) synchronized time. SAASM enables the GPS receiver access to the encrypted P(Y) signal providing protection against active spoofing attacks.</P>
                <P>7. The LAU-129 Guided Missile Launcher is capable of launching a single AIM-9 (Sidewinder) family of missiles or AIM-120 Advanced Medium Range Air-to-Air Missile (AMRAAM). The LAU-129 launcher provides mechanical and electrical interface between missile and aircraft.</P>
                <P>8. The M61A1 Vulcan Cannon is a six-barreled automatic cannon chambered in 20x120mm with a cyclic rate of fire from 2,500-6,000 shots per minute. This weapon is a hydraulically powered air cooled Gatling gun used to damage/destroy aerial targets, suppress/incapacitate personnel targets and damage or destroy moving and stationary light material targets.</P>
                <P>
                    9. The AN/AAQ-33 Sniper Advanced Targeting Pod (ATP) is a single, lightweight targeting pod for military aircraft that provides positive target 
                    <PRTPAGE P="41954"/>
                    identification, autonomous tracking, Global Positioning System (GPS) coordinate generation, and precise weapons guidance from extended standoff ranges. It incorporates a high definition mid-wave Forward-looking infrared (FLIR), dual-mode laser, visible-light High Definition television (HDTV), laser spot tracker, video data link (VDL), and a digital data recorder.
                </P>
                <P>10. The Multifunctional Information Distribution System Joint Tactical Radio Systems (MIDS-JTRS) Link-16 is an advanced command, control, communications, and intelligence (C3I) system incorporating high capacity, jam-resistant, digital communication links for exchange of near real-time tactical information, including both data and voice, among air, ground, and sea elements. It provides the warfighter key theater functions such as surveillance, identification, air control, weapons engagement coordination, and direction for all services and allied forces. With modernized cryptography, Link 16 will ensure interoperability into the future.</P>
                <P>11. AN/ARC-238 radio with HAVE QUICK II is a voice communications radio system that is equipped with HAVE QUICK II, which employs cryptographic technology. Other waveforms may be included as needed.</P>
                <P>12. The AN/APX-126 or equivalent Advanced Identification Friend or Foe (AIFF) Combined Interrogator Transponder (CIT) is a system capable of transmitting and interrogating Mode V. Mode IV and Mode V anti-jam performance specifications/data, software source code, algorithms, and tempest plans or reports will not be offered, released discussed, or demonstrated.</P>
                <P>13. The Joint Helmet Mounted Cueing System II (JHMCS II) or Scorpion Hybrid Optical-based Inertial Tracker (HObIT) is a device used in aircraft to project information to the pilot's eyes and aids in tasks such as cueing weapons and aircraft sensors to air and ground targets. This system projects visual targeting and aircraft performance information on the back of the helmet's visor, enabling the pilot to monitor this information without interrupting his field of view through the cockpit canopy. This provides improvement for close combat targeting and engagement.</P>
                <P>14. The AN/ALQ-254 Viper Shield or equivalent Integrated Electronic Warfare (EW) Suite provides passive radar warning, wide spectrum Radio Frequency (RF) jamming, and control and management of the entire EW system. This system is anticipated to be internal to the aircraft although mounted pod variants are used in certain circumstances.</P>
                <P>15. The AN/ALE-47 Countermeasure Dispenser Set (CMDS) provides an integrated threat-adaptive, computer controlled capability for dispensing chaff, flares, and active radio frequency expendables. The system is internally mounted and may be operated as a stand-alone system or may be integrated with other on-board Electronic Warfare (EW) and avionics systems. The AN/ALE-47 uses threat data received over the aircraft interfaces to assess the threat situation and determine a response. Expendable routines tailored to the immediate aircraft and threat environment may be dispensed using one of four operational modes.</P>
                <P>16. The KY-58M is a lightweight terminal for secure voice and data communications. The KY-58M provides wideband/narrowband half duplex communication.</P>
                <P>17. The KIV-78 is a crypto applique for IFF. It can be loaded with Mode 5 classified elements.</P>
                <P>18. The Simple Key Loader (SKL) is a ruggedized, portable, hand-held device, for securely receiving, storing, and transferring data between compatible cryptographic and communications equipment.</P>
                <P>19. Joint Mission Planning System (JMPS) is a multi-platform PC based mission planning system.</P>
                <P>20. The AIM-120C-8 Advance Medium Range Air-to-Air Missile (AMRAAM) is a supersonic, air launched, aerial intercept, guided missile featuring digital technology and micro-miniature solid-state electronics. AMRAAM capabilities include look-down/shootdown, multiple launches against multiple targets, resistance to electronic countermeasures, and interception of high- and low-flying and maneuvering targets. This potential sale will include AMRAAM Guidance Section spares. The AIM-120C-8 is a form, fit, function refresh of the AIM-120C-7 and is the next generation to be produced.</P>
                <P>21. The AIM-9X Block II SIDEWINDER Tactical is a short-range, air-to-air missile. The AIM-9X Block II SIDEWINDER Missile provides a high off-boresight seeker, enhanced countermeasure rejection capability, low drag/high angle of attack airframe and the ability to integrate the Helmet Mounted Cueing System. This potential sale includes Tactical Guidance Unit Spares.</P>
                <P>22. The AIM-9X Block II Captive Air Training Missile (CATM) is a flight certified inert mass simulator with a functioning Guidance Unit (GU). The CATM is the primary aircrew training device providing all pre-launch functions as well as realistic aerodynamic performance that equate to carrying a tactical missile. The CATM provides pilot training in aerial target acquisition and use of aircraft controls/displays. This potential sale includes CATM Guidance Unit Spares.</P>
                <P>23. The Joint Programmable Fuze FMU-139 or FMU-152 fuzes are multi-delay sensors compatible with weapon guidance kits, tail kits, high-explosive bombs, and reduced collateral damage weapons which provide all arming and detonation event functions combined in a single fuze system.</P>
                <P>24. Laser JDAM (Joint Direct Attack Munitions) (GBU-54) converts existing unguided free-fall bombs into precision guided smart munitions by adding a new tail section containing Inertial Navigation System (INS) guidance/Global Positioning System (GPS) guidance and adds a Semi-active laser seeker. This allows the weapon to strike targets moving at up to 70 mph. The LJDAM weapon consists of a DSU-38 sensor, a JDAM guidance set installed on bomb body and a fuze. The DSU-38 consists of a laser spot tracker (same size and shape as a DSU-33 proximity fuze), a cable connecting the DSU-38 to the basic JDAM guidance set, a cable cover, cable cover tie down straps, modified tail kit door and wiring harness, and associated modified JDAM software that incorporates navigation and guidance flight software to support both LJDAM and standard JDAM missions.</P>
                <P>The KMU-572 is the tail kit for a GBU-54, 500LB Laser JDAM.</P>
                <P>25. The Enhanced Paveway II (EP II) Laser Guided Bomb (LGB) is a maneuverable, all-weather, free-fall weapon that guides to a spot of laser energy reflected off the target. The “enhanced” component is the addition of GPS-aided Inertial Navigation Systems (GAINS) guidance to the laser seeker. Laser designation for the LGB can be provided by a variety of laser target markers or designators. The EP II consists of an MAU-210 Enhanced Computer Control Group (ECCG) that is not warhead specific and a warhead-specific Air Foil Group (AFG) that attaches to the nose and tail of a General Purpose (GP) bomb body.</P>
                <P>The EGBU-49 is a 500LB GP bomb body fitted with the MXU-650 AFG to guide to its laser-designated target.</P>
                <P>26. The Mk-82 GP bomb body is a 500LB, free-fall, unguided, low-drag weapon.</P>
                <P>27. Mk-82 inert GP bomb body is a 500LB, free-fall, unguided, low-drag weapon without the explosive fill.</P>
                <P>
                    28. The GBU-39 Small Diameter Bomb I Practice Bomb is an inert variant of the 250LB, GPS-aided inertial 
                    <PRTPAGE P="41955"/>
                    navigation system, small autonomous, day or night, adverse weather, conventional, air-to-ground precision glide weapon able to strike fixed and stationary re-locatable non-hardened targets from standoff ranges. It can be used for integration, test, or training purposes. This purchase will also include tactical training rounds.
                </P>
                <P>29. The highest level of classification of defense articles, components, and services included in this potential sale is SECRET.</P>
                <P>30. If a technologically advanced adversary were to obtain knowledge of the specific hardware and software elements, the information could be used to develop countermeasures that might reduce weapon system effectiveness or be used in the development of a system with similar or advanced capabilities.</P>
                <P>31. A determination has been made that Bulgaria can provide substantially the same degree of protection for the sensitive technology being released as the U.S. Government. This sale is necessary in furtherance of the U.S. foreign policy and national security objectives outlined in the Policy Justification.</P>
                <P>32. All defense articles and services listed in this transmittal have been authorized for release and export to the Government of Bulgaria.</P>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10473 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 6001-FR-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF DEFENSE</AGENCY>
                <SUBAGY>Office of the Secretary</SUBAGY>
                <DEPDOC>[Transmittal No. 22-04]</DEPDOC>
                <SUBJECT>Arms Sales Notification</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Defense Security Cooperation Agency, Department of Defense (DoD).</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Arms sales notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The DoD is publishing the unclassified text of an arms sales notification.</P>
                </SUM>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Neil Hedlund at 
                        <E T="03">neil.g.hedlund.civ@mail.mil</E>
                         or (703) 697-9214.
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>This 36(b)(1) arms sales notification is published to fulfill the requirements of section 155 of Public Law 104-164 dated July 21, 1996. The following is a copy of a letter to the Speaker of the House of Representatives, Transmittal 22-04 with attached Policy Justification and Sensitivity of Technology.</P>
                <SIG>
                    <DATED>Dated: May 8, 2024.</DATED>
                    <NAME>Aaron T. Siegel,</NAME>
                    <TITLE>Alternate OSD Federal Register Liaison Officer, Department of Defense.</TITLE>
                </SIG>
                <BILCOD>BILLING CODE 6001-FR-P</BILCOD>
                <GPH SPAN="3" DEEP="530">
                    <PRTPAGE P="41956"/>
                    <GID>EN14MY24.117</GID>
                </GPH>
                <BILCOD>BILLING CODE 6001-FR-C</BILCOD>
                <HD SOURCE="HD3">Transmittal No. 22-04 </HD>
                <HD SOURCE="HD3">Notice of Proposed Issuance of Letter of Offer Pursuant to Section 36(b)(1) of the Arms Export Control Act, as amended</HD>
                <P>
                    (i) 
                    <E T="03">Prospective Purchaser:</E>
                     Government of Bahrain
                </P>
                <P>
                    (ii) 
                    <E T="03">Total Estimated Value:</E>
                </P>
                <GPOTABLE COLS="2" OPTS="L0,tp0,p1,8/9,g1,t1,i1" CDEF="s30,14">
                    <TTITLE> </TTITLE>
                    <BOXHD>
                        <CHED H="1"> </CHED>
                        <CHED H="1"> </CHED>
                    </BOXHD>
                    <ROW>
                        <ENT I="01">Major Defense Equipment * </ENT>
                        <ENT>$ 0 million</ENT>
                    </ROW>
                    <ROW RUL="n,s">
                        <ENT I="01">Other </ENT>
                        <ENT>$175.98 million</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">TOTAL </ENT>
                        <ENT>$175.98 million</ENT>
                    </ROW>
                </GPOTABLE>
                <P>Funding Source: National Funds</P>
                <P>
                    (iii) 
                    <E T="03">Description and Quantity or Quantities of Articles or Services under Consideration for Purchase:</E>
                </P>
                <FP SOURCE="FP-2">
                    <E T="03">Major Defense Equipment (MDE):</E>
                </FP>
                <FP SOURCE="FP1-2">None</FP>
                <FP SOURCE="FP-2">
                    <E T="03">Non-MDE:</E>
                </FP>
                <FP SOURCE="FP1-2">
                    Upgrade nine (9) M270 Multiple Launch Rocket Systems (MLRS) to M270 A1 minimum configuration. The upgrade will include: the Common Fire Control System (CFCS); Improved Launcher Mechanical System (ILMS); 600h Engine and associated engine compartment modifications; Improved Electronics Distribution Box (IEDB); fan speed control valve; cables and mounting hardware, Power Take Off (PTO) and BOO series transmission; the Digital Communication Systems (DCOMMS); and Vehicular 
                    <PRTPAGE P="41957"/>
                    Intercom System (AN/VIC-3). In addition, the effort will include two (2) years spare parts; Operator and Maintenance Training Course' Contractor Logistics Support; U.S. Government engineering support; support and test equipment; integration and test support, software delivery and support; publications and technical documentation; technical and logistics support services; storage; and other related elements of logistical and program support.
                </FP>
                <P>
                    (iv) 
                    <E T="03">Military Department:</E>
                     Army (BA-B-ULJ)
                </P>
                <P>
                    (v) 
                    <E T="03">Prior Related Cases, if any:</E>
                     BA-B-JAH, BA-B-UEP, BA-B-UIW
                </P>
                <P>
                    (vi) 
                    <E T="03">Sales Commission, Fee, etc., Paid, Offered, or Agreed to be Paid:</E>
                     None
                </P>
                <P>
                    (vii) 
                    <E T="03">Sensitivity of Technology Contained in the Defense Article or Defense Services Proposed to be Sold:</E>
                     See Attached Annex
                </P>
                <P>
                    (viii) 
                    <E T="03">Date Report Delivered to Congress:</E>
                     March 24, 2022
                </P>
                <P>* As defined in Section 47(6) of the Arms Export Control Act.</P>
                <HD SOURCE="HD2">POLICY JUSTIFICATION</HD>
                <HD SOURCE="HD2">Bahrain—M270 Multiple Launch Rocket Systems (MLRS) Upgrade</HD>
                <P>The Government of Bahrain has requested to buy upgrades to nine (9) M270 Multiple Launch Rocket Systems (MLRS) to a M270 A1 minimum configuration. The upgrade will include: the Common Fire Control System (CFCS); Improved Launcher Mechanical System (ILMS); 600h Engine and associated engine compartment modifications; Improved Electronics Distribution Box (IEDB); fan speed control valve; cables and mounting hardware, Power Take Off (PTO) and BOO series transmission; the Digital Communication Systems (DCOMMS); and Vehicular Intercom System (AN/VIC-3). In addition, the effort will include two (2) years spare parts; Operator and Maintenance Training Course' Contractor Logistics Support; U.S. Government engineering support; support and test equipment; integration and test support, software delivery and support; publications and technical documentation; technical and logistics support services; storage; and other related elements of logistical and program support. The estimated total cost is $175.98 million.</P>
                <P>This proposed sale will support the foreign policy and national security of the United States by helping to improve the security of a Major Non-NATO Ally that is an important force for political stability and economic progress in the Middle East.</P>
                <P>The proposed sale will improve Bahrain's capability to meet current and future threats by enhancing Bahrain's ability to defend itself against regional malign actors and improve interoperability with systems operated by U.S. forces and other Gulf countries. Bahrain's continued investment in its defensive capabilities is crucial to protecting its borders, energy infrastructure, and its residents, including over 15,000 U.S. citizens and Naval personnel living and working in the country. Bahrain will have no difficulty absorbing these upgraded MLRSs into its armed forces.</P>
                <P>The proposed sale of this equipment and support will not alter the basic military balance in the region.</P>
                <P>The principal contractor will be the Lockheed Martin Corporation, Bethesda, MD. There are no known offset agreements proposed in connection with this potential sale.</P>
                <P>Implementation of this proposed sale will not require the assignment of any additional U.S. Government or contractor representatives to Bahrain.</P>
                <P>There will be no adverse impact on U.S. defense readiness as a result of this proposed sale.</P>
                <HD SOURCE="HD3">Transmittal No. 22-04</HD>
                <HD SOURCE="HD3">Notice of Proposed Issuance of Letter of Offer Pursuant to Section 36(b)(1) of the Arms Export Control Act</HD>
                <HD SOURCE="HD3">Annex</HD>
                <HD SOURCE="HD3">Item No. vii</HD>
                <P>
                    (vii) 
                    <E T="03">Sensitivity of Technology:</E>
                </P>
                <P>1. The Multiple Launch Rocket System (MLRS) is a high-mobility automatic system based on an M270 weapons platform. The MLRS fires surface-to-surface rockets: the Army Tactical Missile System (ATACMS) and the Guided Multiple Launch Rocket System (GMLRS). Without leaving the cab, the crew of three (driver, gunner and section chief) can fire up to 12 MLRS rockets in fewer than 60 seconds.</P>
                <P>2. The highest level of classification of defense articles, components, and services included in this potential sale is SECRET.</P>
                <P>3. If a technologically advanced adversary were to obtain knowledge of the specific hardware and software elements, the information could be used to develop countermeasures that might reduce weapon system effectiveness or be used in the development of a system with similar or advanced capabilities.</P>
                <P>4. A determination has been made that the Government of Bahrain can provide substantially the same degree of protection for the sensitive technology being released as the U.S. Government. This sale is necessary in furtherance of the U.S. foreign policy and national security objectives outlined in the Policy Justification.</P>
                <P>5. All defense articles and services listed in this transmittal have been authorized for release and export to the Government of Bahrain.</P>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10472 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 6001-FR-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF DEFENSE</AGENCY>
                <SUBAGY>Office of the Secretary</SUBAGY>
                <DEPDOC>[Transmittal No. 22-18]</DEPDOC>
                <SUBJECT>Arms Sales Notification</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Defense Security Cooperation Agency, Department of Defense (DoD).</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Arms sales notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The DoD is publishing the unclassified text of an arms sales notification.</P>
                </SUM>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Neil Hedlund at 
                        <E T="03">neil.g.hedlund.civ@mail.mil</E>
                         or (703) 697-9214.
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>This 36(b)(1) arms sales notification is published to fulfill the requirements of section 155 of Public Law 104-164 dated July 21, 1996. The following is a copy of a letter to the Speaker of the House of Representatives, Transmittal 22-18 with attached Policy Justification.</P>
                <SIG>
                    <DATED>Dated: May 8, 2024.</DATED>
                    <NAME>Aaron T. Siegel,</NAME>
                    <TITLE>Alternate OSD Federal Register Liaison Officer, Department of Defense.</TITLE>
                </SIG>
                <BILCOD>BILLING CODE 6001-FR-P</BILCOD>
                <GPH SPAN="3" DEEP="530">
                    <PRTPAGE P="41958"/>
                    <GID>EN14MY24.115</GID>
                </GPH>
                <BILCOD>BILLING CODE 6001-FR-C</BILCOD>
                <HD SOURCE="HD3">Transmittal No. 22-18 </HD>
                <HD SOURCE="HD3">Notice of Proposed Issuance of Letter of Offer Pursuant to Section 36(b)(1) of the Arms Export Control Act, as amended</HD>
                <P>
                    (i) 
                    <E T="03">Prospective Purchaser:</E>
                     Government of the United Kingdom
                </P>
                <P>
                    (ii) 
                    <E T="03">Total Estimated Value:</E>
                </P>
                <GPOTABLE COLS="2" OPTS="L0,tp0,p1,8/9,g1,t1,i1" CDEF="s30,14">
                    <TTITLE> </TTITLE>
                    <BOXHD>
                        <CHED H="1"> </CHED>
                        <CHED H="1"> </CHED>
                    </BOXHD>
                    <ROW>
                        <ENT I="01">Major Defense Equipment * </ENT>
                        <ENT>$ 0 million</ENT>
                    </ROW>
                    <ROW RUL="n,s">
                        <ENT I="01">Other </ENT>
                        <ENT>$ 368.53 million</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">TOTAL</ENT>
                        <ENT>$ 368.53 million</ENT>
                    </ROW>
                </GPOTABLE>
                <P>
                    (iii) 
                    <E T="03">Description and Quantity or Quantities of Articles or Services under Consideration for Purchase:</E>
                </P>
                <FP SOURCE="FP-2">
                    <E T="03">Major Defense Equipment (MDE):</E>
                </FP>
                <FP SOURCE="FP1-2">None</FP>
                <FP SOURCE="FP-2">
                    <E T="03">Non-MDE:</E>
                </FP>
                <FP SOURCE="FP1-2">
                    Follow-on support for all three segments of the United Kingdom's (UK) Tomahawk Weapon System (TWS). This includes the All Up Round (AUR), Tactical Tomahawk Weapon Control System (TTWCS) and Theater Mission Planning Center (TMPC). The support includes recertification of the UK's missiles; unscheduled missile maintenance; spares; procurement; training; in-service support; software; hardware; communication equipment; operational flight test; engineering and technical expertise to maintain the TWS capability; and other related elements of logistical 
                    <PRTPAGE P="41959"/>
                    and program support.
                </FP>
                <P>
                    (iv) 
                    <E T="03">Military Department:</E>
                     Navy (UK-P-FCS)
                </P>
                <P>
                    (v) 
                    <E T="03">Prior Related Cases, if any:</E>
                     UK-P-AGS, UK-P-AHA, UK-P-AHE, UK-P-AHJ, UK-P-AHS, UK-P-FAY, UK-P-FBX, UK-P-GEK, UK-P-GWY, UK-P-GXQ, UK-P-GYU, UK-P-LIS
                </P>
                <P>
                    (vi) 
                    <E T="03">Sales Commission, Fee, etc., Paid, Offered, or Agreed to be Paid:</E>
                     None
                </P>
                <P>
                    (vii) 
                    <E T="03">Sensitivity of Technology Contained in the Defense Article or Defense Services Proposed to be Sold:</E>
                     None
                </P>
                <P>
                    (viii) 
                    <E T="03">Date Report Delivered to Congress:</E>
                     March 29, 2022
                </P>
                <P>* As defined in Section 47(6) of the Arms Export Control Act.</P>
                <HD SOURCE="HD2">POLICY JUSTIFICATION</HD>
                <HD SOURCE="HD2">United Kingdom—Tomahawk Weapon System (TWS) Follow-On Support</HD>
                <P>The Government of the United Kingdom (UK) has requested to buy follow-on support for all three segments of the United Kingdom's Tomahawk Weapon System (TWS). This includes the All Up Round (AUR), Tactical Tomahawk Weapon Control System (TTWCS) and Theater Mission Planning Center (TMPC). The support includes recertification of the UK's missiles; unscheduled missile maintenance; spares; procurement; training; in-service support; software; hardware; communication equipment; operational flight test; engineering and technical expertise to maintain the TWS capability; and other related elements of logistical and program support. The total estimated program cost is $368.53 million.</P>
                <P>This proposed sale will support the foreign policy goals and national security objectives of the United States by improving the security of a NATO Ally that is a force for political stability and economic progress in Europe.</P>
                <P>The proposed sale will sustain the operating capability of the United Kingdom, ensuring maritime forces' interoperability with United States and other allied forces as well as their ability to contribute to missions of mutual interest by delivering follow-on support and sustainment. By deploying the Tomahawk Weapon system, the United Kingdom contributes to global readiness and enhances the capability for the U.S. forces operating globally alongside them. The United Kingdom already operates this capability, and will have no difficulty absorbing this equipment into its armed forces.</P>
                <P>The proposed sale of this equipment and support will not alter the basic military balance in the region.</P>
                <P>The prime contractor will be Raytheon Missiles and Defense, Tucson, AZ. There are no known offset agreements proposed in connection with this potential sale.</P>
                <P>Implementation of this proposed sale will require multiple trips by U.S. Government representatives and the assignment of contractor representatives to United Kingdom on an intermittent basis over the life of the case to support delivery and integration of items and to provide supply support management, inventory control and equipment familiarization. There will be one (1) U.S. Government representative and three (3) U.S. contractor representatives in the UK full-time for the duration of the case.</P>
                <P>There will be no adverse impact on U.S. defense readiness as a result of this proposed sale.</P>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10469 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 6001-FR-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF DEFENSE</AGENCY>
                <SUBAGY>Office of the Secretary</SUBAGY>
                <DEPDOC>[Transmittal No. 22-0E]</DEPDOC>
                <SUBJECT>Arms Sales Notification</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Defense Security Cooperation Agency, Department of Defense (DoD).</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Arms sales notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The DoD is publishing the unclassified text of an arms sales notification.</P>
                </SUM>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Neil Hedlund at 
                        <E T="03">neil.g.hedlund.civ@mail.mil</E>
                         or (703) 697-9214.
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>This 36(b)(5)(C) arms sales notification is published to fulfill the requirements of section 155 of Public Law 104-164 dated July 21, 1996. The following is a copy of a letter to the Speaker of the House of Representatives with the attached Transmittal 22-0E.</P>
                <SIG>
                    <DATED>Dated: May 8, 2024.</DATED>
                    <NAME>Aaron T. Siegel,</NAME>
                    <TITLE>Alternate OSD Federal Register Liaison Officer, Department of Defense.</TITLE>
                </SIG>
                <BILCOD>BILLING CODE 6001-FR-P</BILCOD>
                <GPH SPAN="3" DEEP="489">
                    <PRTPAGE P="41960"/>
                    <GID>EN14MY24.116</GID>
                </GPH>
                <BILCOD>BILLING CODE 6001-FR-C</BILCOD>
                <HD SOURCE="HD3">Transmittal No. 22-0E</HD>
                <HD SOURCE="HD2">REPORT OF ENHANCEMENT OR UPGRADE OF SENSITIVITY OF TECHNOLOGY OR CAPABILITY (SEC. 36(B)(5)(C), AECA)</HD>
                <P>
                    (i) 
                    <E T="03">Purchaser:</E>
                     Government of France
                </P>
                <P>
                    (ii) 
                    <E T="03">Sec. 36(b)(1), AECA Transmittal No.:</E>
                     20-40
                </P>
                <P>Date: July 6, 2020</P>
                <P>Military Department: Navy</P>
                <P>
                    (iii) 
                    <E T="03">Description:</E>
                     On July 6, 2020, Congress was notified by Congressional certification transmittal number 20-40, of the possible sale, under Section 36(b)(1) of the Arms Export Control Act, of three (3) E-2D Advanced Hawkeye Aircraft, ten (10) T-56-427A engines (6 installed and 4 spares), three (3) AN/APY-9 radar assemblies, four (4) AN/ALQ-217 electronic support measure systems (3 installed and 1 spare), three (3) AN/AYK-27 Integrated Navigation Channels and Display Systems, five (5) Link-16 (MIDS-JTRS) Communications Systems (3 installed and 2 spares), ten (10) Embedded GPS/INS (EGI) Devices (6 installed and 4 spares), four (4) AN/APX-122(A) and AN/APX-123(A) Identification, Friend or Foe systems (3 installed and 1 spare) and one (1) Joint Mission Planning System. Also included were Common Systems Integration Laboratories with/Test Equipment, one in Melbourne, FL, and the other in France; air and ground crew equipment; support equipment; spare and repair parts; publications and technical documentation; transportation; training and training equipment; U.S. Government and contractor logistics, engineering, and technical support services; and other related elements of logistics and program support. The estimated total cost was $2 billion. Major Defense Equipment (MDE) constituted $1.3 billion of this total.
                </P>
                <P>
                    This transmittal notifies the inclusion of: one (1) Tactics Trainer—Weapon 
                    <PRTPAGE P="41961"/>
                    Systems (TT) (MDE). Also included are additional training devices, spares, and services. The total estimated MDE value will increase by $42 million, resulting in a new MDE total of $1.35 billion. The total estimated case value will increase to $2.1 billion.
                </P>
                <P>
                    (iv) 
                    <E T="03">Significance:</E>
                     The proposed sale will improve France's ongoing E-2D acquisition. These trainers directly support France's capabilities for Electronic Warfare, air safety, NATO missions, and interoperability with U.S. forces.
                </P>
                <P>
                    (v) 
                    <E T="03">Justification:</E>
                     This proposed sale will support the foreign policy and national security of the United States by helping to improve the security of a NATO ally which is an important force for political stability and economic progress in Europe.
                </P>
                <P>
                    (vi) 
                    <E T="03">Sensitivity of Technology:</E>
                     The E-2D Tactics Trainer—Weapon Systems (TT) delivers a comprehensive and dynamic high fidelity environment simulating the E-2D Advanced Hawkeye (AHE) Combat Information Center (CIC) and related aircraft subsystems. The TT provides coordinated ground based qualification and continuation training for Naval Flight Officer (NFO) crew positions of the E-2D including: Air Control Officer (ACO), Combat Information Center Officer (CICO), Radar Officer (RO), and Tactical Forth Operator and an Instructor Operation Station (IOS) for simulation control and recording of student performance.
                </P>
                <P>The highest level of classification of defense articles, components, and services included in this potential sale is SECRET.</P>
                <P>
                    (vii) 
                    <E T="03">Date Report Delivered to Congress:</E>
                     April 5, 2022
                </P>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10471 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 6001-FR-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF DEFENSE</AGENCY>
                <SUBAGY>Office of the Secretary</SUBAGY>
                <DEPDOC>[Transmittal No. 22-10]</DEPDOC>
                <SUBJECT>Arms Sales Notification</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Defense Security Cooperation Agency, Department of Defense (DoD).</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Arms sales notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The DoD is publishing the unclassified text of an arms sales notification.</P>
                </SUM>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Neil Hedlund at 
                        <E T="03">neil.g.hedlund.civ@mail.mil</E>
                         or (703) 697-9214.
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>This 36(b)(1) arms sales notification is published to fulfill the requirements of section 155 of Public Law 104-164 dated July 21, 1996. The following is a copy of a letter to the Speaker of the House of Representatives, Transmittal 22-10 with attached Policy Justification and Sensitivity of Technology.</P>
                <SIG>
                    <DATED>Dated: May 8, 2024.</DATED>
                    <NAME>Aaron T. Siegel,</NAME>
                    <TITLE>Alternate OSD Federal Register Liaison Officer, Department of Defense.</TITLE>
                </SIG>
                <BILCOD>BILLING CODE 6001-FR-P</BILCOD>
                <GPH SPAN="3" DEEP="546">
                    <PRTPAGE P="41962"/>
                    <GID>EN14MY24.118</GID>
                </GPH>
                <BILCOD>BILLING CODE 6001-FR-C</BILCOD>
                <HD SOURCE="HD3">Transmittal No. 22-10</HD>
                <HD SOURCE="HD3">Notice of Proposed Issuance of Letter of Offer Pursuant to Section 36(b)(1) of the Arms Export Control Act, as amended</HD>
                <P>
                    (i) 
                    <E T="03">Prospective Purchaser:</E>
                     Government of the United Kingdom
                </P>
                <P>
                    (ii) 
                    <E T="03">Total Estimated Value:</E>
                </P>
                <GPOTABLE COLS="2" OPTS="L0,tp0,p1,8/9,g1,t1,i1" CDEF="s30,xs50">
                    <TTITLE> </TTITLE>
                    <BOXHD>
                        <CHED H="1"> </CHED>
                        <CHED H="1"> </CHED>
                    </BOXHD>
                    <ROW>
                        <ENT I="01">Major Defense Equipment *</ENT>
                        <ENT>$400 million</ENT>
                    </ROW>
                    <ROW RUL="n,s">
                        <ENT I="01">Other</ENT>
                        <ENT>$300 million</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="03">TOTAL</ENT>
                        <ENT>$700 million</ENT>
                    </ROW>
                </GPOTABLE>
                <P>
                    (iii) 
                    <E T="03">Description and Quantity or Quantities of Articles or Services under Consideration for Purchase:</E>
                </P>
                <FP SOURCE="FP-2">
                    <E T="03">Major Defense Equipment (MDE):</E>
                </FP>
                <FP SOURCE="FP1-2">One (1) Ballistic Missile Defense Radar (BMDR)</FP>
                <FP SOURCE="FP1-2">Two (2) Command and Control Battle Management and Communications (C2BMC) User Nodes (with network capability required to connect to the C2BMC System to support radar operations)</FP>
                <FP SOURCE="FP-2">
                    <E T="03">Non-MDE:</E>
                </FP>
                <FP SOURCE="FP1-2">
                    Also included are design and construction of a combined radar-equipment shelter; encryption devices, secure communication equipment, and other required COMSEC equipment to support 
                    <PRTPAGE P="41963"/>
                    radar operations; spare and repair parts, support and testing equipment, publications and technical documentation, personnel training and training equipment, U.S. Government and contractor engineering, technical and logistics support services, and other related elements of logistical and program support.
                </FP>
                <P>
                    (iv) 
                    <E T="03">Military Department:</E>
                     Missile Defense Agency (UK-I-ZAB)
                </P>
                <P>
                    (v) 
                    <E T="03">Prior Related Cases, if any:</E>
                     UK-I-ZAA
                </P>
                <P>
                    (vi) 
                    <E T="03">Sales Commission, Fee, etc., Paid, Offered, or Agreed to be Paid:</E>
                     None
                </P>
                <P>
                    (vii) 
                    <E T="03">Sensitivity of Technology Contained in the Defense Article or Defense Services Proposed to be Sold:</E>
                     See Attached Annex
                </P>
                <P>
                    (viii) 
                    <E T="03">Date Report Delivered to Congress:</E>
                     March 17, 2022
                </P>
                <P>* As defined in Section 47(6) of the Arms Export Control Act.</P>
                <HD SOURCE="HD2">POLICY JUSTIFICATION</HD>
                <HD SOURCE="HD2">United Kingdom—Ballistic Missile Defense Radar (BMDR) and Command and Control Battle Management and Communications (C2BMC)</HD>
                <P>The Government of the United Kingdom (UK) has requested to buy one (1) Ballistic Missile Defense Radar (BMDR); and two (2) Command and Control Battle Management and Communications (C2BMC) user nodes (with network capability required to connect to the C2BMC System to support radar operations). Also included are design and construction of a combined radar-equipment shelter; encryption devices, secure communication equipment, and other required COMSEC equipment to support radar operations; spare and repair parts, support and testing equipment, publications and technical documentation, personnel training and training equipment, U.S. Government and contractor engineering, technical and logistics support services, and other related elements of logistical and program support. The total estimated program cost is $700 million.</P>
                <P>This proposed sale will support the foreign policy goals and national security objectives of the United States by improving the security of a NATO Ally that is a force for political stability and economic progress in Europe.</P>
                <P>The proposed sale will improve UK's ability to meet current and future ballistic missile threats to the UK and NATO by improving the effectiveness of NATO BMD systems. The United Kingdom will have no difficulty absorbing the BMD Radar into its armed forces.</P>
                <P>The proposed sale of this equipment and support will not alter the basic military balance in the region.</P>
                <P>The principal contractor will be Lockheed Martin, Moorestown, NJ. There are no known offset agreements proposed in connection with this potential sale.</P>
                <P>Implementation of this proposed sale may require the assignment of approximately 15 U.S. Government and up to 100 contractor representatives to the UK, at any given time, during the construction, installation, integration and testing of the BMDR and C2BMC capability.</P>
                <P>There will be no adverse impact on U.S. defense readiness as a result of this proposed sale.</P>
                <HD SOURCE="HD3">Transmittal No. 22-10</HD>
                <HD SOURCE="HD3">Notice of Proposed Issuance of Letter of Offer Pursuant to Section 36(b)(1) of the Arms Export Control Act</HD>
                <HD SOURCE="HD3">Annex</HD>
                <HD SOURCE="HD3">Item No. vii</HD>
                <P>
                    (vii) 
                    <E T="03">Sensitivity of Technology:</E>
                </P>
                <P>1. The United Kingdom (UK) Ballistic Missile Defense Radar (BMDR) is a scaled version of the U.S. Long Range Discrimination Radar. It will provide continuous and precise tracking and discrimination of missile threats, persistent long-range midcourse discrimination, precision tracking and hit assessment. Discrimination is a critical capability of missile defense, which will provide data to distinguish lethal objects from debris and decoys around the lethal object. The UK will use the Command and Control, Battle Management, and Communications (C2BMC) system to integrate the UK BMDR. This will improve the effectiveness of North Atlantic Treaty Organization (NATO) missile defenses.</P>
                <P>2. The highest level of classification of defense articles, components, and services included in this potential sale is SECRET.</P>
                <P>3. If a technologically advanced adversary were to obtain knowledge of the hardware and software elements, the information could be used to develop countermeasures or equivalent systems, which might reduce system effectiveness or be used in the development of a system with similar or advanced capabilities.</P>
                <P>4. A determination has been made that the United Kingdom can provide substantially the same degree of protection for the sensitive technology being released as the U.S. Government. This sale is necessary in furtherance of the U.S. foreign policy and national security objectives outlined in the Policy Justification.</P>
                <P>5. All defense articles and services listed in this transmittal have been authorized for release and export to the Government of the United Kingdom.</P>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10470 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 6001-FR-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF DEFENSE</AGENCY>
                <SUBAGY>Office of the Secretary</SUBAGY>
                <SUBJECT>Charter Renewal Department of Defense Federal Advisory Committees—Board on Coastal Engineering Research</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Department of Defense (DoD).</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Federal advisory committee charter renewal.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The DoD is publishing this notice to announce that it has renewed the charter for the Board on Coastal Engineering Research (BCER).</P>
                </SUM>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Jim Freeman, DoD Advisory Committee Management Officer, 703-692-5952.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    The BCER charter is being renewed in accordance with chapter 10 of title 5, United States Code (U.S.C.) (commonly known as the “Federal Advisory Committee Act” or “FACA”) and 41 Code of Federal Regulations (CFR) 102-3.50(a). The charter and contact information for the BCER's Designated Federal Officer (DFO) are found at 
                    <E T="03">https://www.facadatabase.gov/FACA/apex/FACAPublicAgencyNavigation.</E>
                </P>
                <P>Pursuant to 33 U.S.C. 426-2, the BCER provides independent advice and recommendations on the functions of the Coastal Engineering Research Center (CERC). The BCER provides independent advice and recommendations on the work of the Coastal and Hydraulics Laboratory, which includes the CERC, on coastal engineering research priorities and additional functions as assigned by the Commanding General, U.S. Army Corps of Engineers (USACE) (“the Chief of Engineers”).</P>
                <P>
                    Pursuant to 33 U.S.C. 426, the BCER shall be composed of seven members. Four members of the BCER will be officers of the USACE and serve as ex-officio members with one position being occupied by the Deputy Commanding General for Civil and Emergency Operations, USACE for no fixed term of service. The remaining three BCER members shall be civilian engineers who are selected with regard to their special fitness in the field of beach erosion and shore protection. The Deputy Commanding General for Civil 
                    <PRTPAGE P="41964"/>
                    and Emergency Operations, USACE, shall serve as the President of the Board.
                </P>
                <P>The appointment of the civilian BCER members and the three coastal division commanders shall be approved by the Secretary of Defense or the Deputy Secretary of Defense (the DoD Appointing Authority), for a term of service of one-to-four years, in accordance with DoD policy and procedures. BCER members who are not full-time or permanent part-time Federal civilian officers or employees, or active-duty members of the Uniformed Services, are appointed as experts or consultants, pursuant to 5 U.S.C. 3109, to serve as special government employee members (SGE). BCER members who are full-time or permanent part-time Federal civilian officers or employees, or active-duty members of the Uniformed Services are appointed pursuant to 41 CFR 102-3.130(a), to serve as regular government employee (RGE) members. No member, unless approved by the DoD Appointing Authority, may serve more than two consecutive terms of service on the BCER or serve on more than two DoD Federal advisory committees at one time.</P>
                <P>All BCER members are appointed to provide advice on the basis of their best judgment without representing any particular point of view and in a manner that is free from conflict of interest. Pursuant to section 105 of Public Law 91-611, SGE members on the BCER may be paid at a rate not to exceed the daily equivalent of the rate for a GS-15, step 10, for each day of attendance at BCER meetings, not to exceed 30 days per year, in addition to travel and other necessary expenses connected with their official duties on the BCER, in accordance with the provisions of 5 U.S.C. 5703(b), (d), and 5707. RGE members may be reimbursed for official BCER-related travel and per diem.</P>
                <P>The public or interested organizations may submit written statements about BCER mission and functions. Written statements may be submitted at any time or in response to a stated agenda of a planned meeting of the BCER. All written statements shall be submitted to the DFO for the BCER, and this individual will ensure that the written statements are provided to the membership for their consideration.</P>
                <SIG>
                    <DATED>Dated: May 8, 2024.</DATED>
                    <NAME>Aaron T. Siegel,</NAME>
                    <TITLE>Alternate OSD Federal Register Liaison Officer, Department of Defense.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10478 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 6001-FR-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF EDUCATION</AGENCY>
                <SUBAGY>National Assessment Governing Board</SUBAGY>
                <SUBJECT> Meeting; Correction</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>National Assessment Governing Board, Department of Education.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice; correction.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>
                        The National Assessment Governing Board (Governing Board) published a document in the 
                        <E T="04">Federal Register</E>
                         on Friday, May 3, 2024 announcing the schedule and proposed agenda of the May 16-17, 2024 quarterly meeting of the Governing Board. The meeting agenda has been revised to reflect the below changes to the Friday sessions of the Governing Board meeting.
                    </P>
                </SUM>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Angela Scott (202) 357-7502.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                     In the 
                    <E T="04">Federal Register</E>
                     of May 3, 2024, in FR Doc. 2024-09695, at 89 FR 36782-236783, the agenda has been revised to reflect new times for these meetings. The NCES Commissioner's update will now be held on Friday, May 17, 2024, from 10:30 a.m. to 11:00 a.m., the NAEP 2024 Administration update and discussion will be held from 11:00 a.m. to 11:45 a.m., and the NAEP budget and contracts update will be held from 12:45 p.m. to 2:30 p.m. The meeting will end at 2:30 p.m. which is 15 minutes later than the originally published end time of 2:15 p.m.
                </P>
                <SIG>
                    <NAME>Lesley A. Muldoon,</NAME>
                    <TITLE>Executive Director, National Assessment Governing Board (NAGB), U.S. Department of Education.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10505 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4000-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF EDUCATION</AGENCY>
                <DEPDOC>[Docket No.: ED-2024-SCC-0037]</DEPDOC>
                <SUBJECT>Agency Information Collection Activities; Submission to the Office of Management and Budget for Review and Approval; Comment Request; Campus Safety and Security Survey</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Office of Postsecondary Education (OPE), Department of Education (ED).</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>In accordance with the Paperwork Reduction Act (PRA) of 1995, the Department is proposing an extension without change of a currently approved information collection request (ICR).</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Interested persons are invited to submit comments on or before June 13, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Written comments and recommendations for proposed information collection requests should be submitted within 30 days of publication of this notice. Click on this link 
                        <E T="03">www.reginfo.gov/public/do/PRAMain</E>
                         to access the site. Find this information collection request (ICR) by selecting “Department of Education” under “Currently Under Review,” then check the “Only Show ICR for Public Comment” checkbox. Reginfo.gov provides two links to view documents related to this information collection request. Information collection forms and instructions may be found by clicking on the “View Information Collection (IC) List” link. Supporting statements and other supporting documentation may be found by clicking on the “View Supporting Statement and Other Documents” link.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>For specific questions related to collection activities, please contact Amy Wilson, 202-987-1318.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The Department is especially interested in public comment addressing the following issues: (1) is this collection necessary to the proper functions of the Department; (2) will this information be processed and used in a timely manner; (3) is the estimate of burden accurate; (4) how might the Department enhance the quality, utility, and clarity of the information to be collected; and (5) how might the Department minimize the burden of this collection on the respondents, including through the use of information technology. Please note that written comments received in response to this notice will be considered public records.</P>
                <P>
                    <E T="03">Title of Collection:</E>
                     Campus Safety and Security Survey.
                </P>
                <P>
                    <E T="03">OMB Control Number:</E>
                     1840-0833.
                </P>
                <P>
                    <E T="03">Type of Review:</E>
                     An extension without change of a currently approved ICR.
                </P>
                <P>
                    <E T="03">Respondents/Affected Public:</E>
                     Private sector; State, local, and Tribal governments.
                </P>
                <P>
                    <E T="03">Total Estimated Number of Annual Responses:</E>
                     5,784.
                </P>
                <P>
                    <E T="03">Total Estimated Number of Annual Burden Hours:</E>
                     2,410.
                </P>
                <P>
                    <E T="03">Abstract:</E>
                     The collection of information through the Campus Safety and Security Survey (CSS) is necessary under section 485 of the Higher Education Act of 1965, as amended, with the goal of increasing transparency surrounding college safety and security information for students, prospective students, parents, employees and the 
                    <PRTPAGE P="41965"/>
                    general public. The survey is a collection tool to compile the annual data on campus crime and fire safety. The data collected from the individual institutions by the Department of Education (ED) is made available to the public through the Campus Safety and Security Data Analysis and Cutting Tool as well as the College Navigator.
                </P>
                <SIG>
                    <DATED>Dated: May 9, 2024.</DATED>
                    <NAME>Kun Mullan,</NAME>
                    <TITLE>PRA Coordinator, Strategic Collections and Clearance, Governance and Strategy Division, Office of Chief Data Officer, Office of Planning, Evaluation and Policy Development.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10488 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4000-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF ENERGY</AGENCY>
                <SUBJECT>Environmental Management Site-Specific Advisory Board, Portsmouth</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Office of Environmental Management, Department of Energy.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of open meeting.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>
                        This notice announces a meeting of the Environmental Management Site-Specific Advisory Board (EM SSAB), Portsmouth. The Federal Advisory Committee Act requires that public notice of this meeting be announced in the 
                        <E T="04">Federal Register</E>
                        .
                    </P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Thursday, June 6, 2024; 6 p.m.-8 p.m. EDT</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>The Ohio State University, Endeavor Center, 1862 Shyville Road, Room 165, Piketon, Ohio 45661.</P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Greg Simonton, Federal Coordinator, by Phone: (740) 897-3737 or Email: 
                        <E T="03">greg.simonton@pppo.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P/>
                <P>
                    <E T="03">Purpose of the Board:</E>
                     The purpose of the Board is to provide advice and recommendations concerning the following EM site-specific issues: clean-up activities and environmental restoration; waste and nuclear materials management and disposition; excess facilities; future land use and long-term stewardship. The Board may also be asked to provide advice and recommendations on any EM program components.
                </P>
                <HD SOURCE="HD2">Tentative Agenda</HD>
                <FP SOURCE="FP-1">• Presentation</FP>
                <FP SOURCE="FP-1">• Administrative Activities</FP>
                <FP SOURCE="FP-1">• Public Comments</FP>
                <P>
                    <E T="03">Public Participation:</E>
                     The meeting is open to the public. The EM SSAB, Portsmouth, will make every effort to accommodate persons with physical disabilities or special needs. If you require special accommodations due to a disability, please contact Greg Simonton in advance of the meeting at the telephone number listed above. The EM SSAB, Portsmouth will hear oral public comments during the meeting. Written statements may be filed either before or after the meeting. Written comments received no later than 5 p.m. EDT on Friday, May 31, 2024, will be read aloud during the meeting. Written comments submitted by 5 p.m. EDT on Friday, June 14, 2024 will be included in the minutes. Please submit written comments to Greg Simonton with “Public Comment” in the subject line. The Deputy Designated Federal Officer is empowered to conduct the meeting in a fashion that will facilitate the orderly conduct of business.
                </P>
                <P>
                    <E T="03">Minutes:</E>
                     Minutes will be available by writing or calling Greg Simonton, Federal Coordinator, U.S. Department of Energy, Portsmouth/Paducah Project Office, P.O. Box 700, Piketon, OH 45661, Email: 
                    <E T="03">greg.simonton@pppo.gov</E>
                     or by Phone: (740) 897-3737. Minutes will also be available at the following website: 
                    <E T="03">https://www.energy.gov/pppo/ports-ssab/listings/meeting-materials.</E>
                </P>
                <P>
                    <E T="03">Signing Authority:</E>
                     This document of the Department of Energy was signed on May 8, 2024, by David Borak, Deputy Committee Management Officer, pursuant to delegated authority from the Secretary of Energy. That document with the original signature and date is maintained by DOE. For administrative purposes only, and in compliance with requirements of the Office of the Federal Register, the undersigned DOE Federal Register Liaison Officer has been authorized to sign and submit the document in electronic format for publication, as an official document of the Department of Energy. This administrative process in no way alters the legal effect of this document upon publication in the 
                    <E T="04">Federal Register</E>
                    .
                </P>
                <SIG>
                    <DATED>Signed in Washington, DC, on May 9, 2024.</DATED>
                    <NAME>Treena V. Garrett,</NAME>
                    <TITLE>Federal Register Liaison Officer, U.S. Department of Energy.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10489 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 6450-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF ENERGY</AGENCY>
                <SUBAGY>Federal Energy Regulatory Commission</SUBAGY>
                <SUBJECT>Combined Notice of Filings</SUBJECT>
                <P>Take notice that the Commission has received the following Natural Gas Pipeline Rate and Refund Report filings:</P>
                <HD SOURCE="HD1">Filings Instituting Proceedings</HD>
                <P>
                    <E T="03">Docket Numbers:</E>
                     RP24-763-000.
                </P>
                <P>
                    <E T="03">Applicants:</E>
                     LA Storage, LLC.
                </P>
                <P>
                    <E T="03">Description:</E>
                     4(d) Rate Filing: Filing of Negotiated Rate, Conforming IW Agreement 5.7.2024 to be effective 5/8/2024.
                </P>
                <P>
                    <E T="03">Filed Date:</E>
                     5/7/24.
                </P>
                <P>
                    <E T="03">Accession Number:</E>
                     20240507-5136.
                </P>
                <P>
                    <E T="03">Comment Date:</E>
                     5 p.m. ET 5/20/24.
                </P>
                <P>
                    <E T="03">Docket Numbers:</E>
                     RP24-764-000.
                </P>
                <P>
                    <E T="03">Applicants:</E>
                     Gulfstream Natural Gas System, L.L.C.
                </P>
                <P>
                    <E T="03">Description:</E>
                     4(d) Rate Filing: Contact Person Update Filing to be effective 6/8/2024.
                </P>
                <P>
                    <E T="03">Filed Date:</E>
                     5/8/24.
                </P>
                <P>
                    <E T="03">Accession Number:</E>
                     20240508-5028.
                </P>
                <P>
                    <E T="03">Comment Date:</E>
                     5 p.m. ET 5/20/24.
                </P>
                <P>Any person desiring to intervene, to protest, or to answer a complaint in any of the above proceedings must file in accordance with Rules 211, 214, or 206 of the Commission's Regulations (18 CFR 385.211, 385.214, or 385.206) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.</P>
                <P>
                    The filings are accessible in the Commission's eLibrary system (
                    <E T="03">https://elibrary.ferc.gov/idmws/search/fercgensearch.asp</E>
                    ) by querying the docket number.
                </P>
                <P>
                    eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at: 
                    <E T="03">http://www.ferc.gov/docs-filing/efiling/filing-req.pdf.</E>
                     For other information, call (866) 208-3676 (toll free). For TTY, call (202) 502-8659.
                </P>
                <P>
                    The Commission's Office of Public Participation (OPP) supports meaningful public engagement and participation in Commission proceedings. OPP can help members of the public, including landowners, environmental justice communities, Tribal members and others, access publicly available information and navigate Commission processes. For public inquiries and assistance with making filings such as interventions, comments, or requests for rehearing, the public is encouraged to contact OPP at (202) 502-6595 or 
                    <E T="03">OPP@ferc.gov.</E>
                </P>
                <SIG>
                    <DATED>Dated: May 8, 2024.</DATED>
                    <NAME>Debbie-Anne A. Reese,</NAME>
                    <TITLE>Acting Secretary.</TITLE>
                </SIG>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10549 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 6717-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <PRTPAGE P="41966"/>
                <AGENCY TYPE="N">FEDERAL ELECTION COMMISSION</AGENCY>
                <DEPDOC>[Notice 2024-14]</DEPDOC>
                <SUBJECT>Filing Dates for the New Jersey Special Election in the 10th Congressional District</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Election Commission.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of filing dates for special election.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>New Jersey has scheduled special elections on July 16, 2024, and September 18, 2024, to fill the U.S. House of Representatives seat in the 10th Congressional District of the late Representative Donald M. Payne, Jr. Committees required to file reports in connection with the Special Primary Election on July 16, 2024, shall file a 12-day Pre-Primary Report. Committees required to file reports in connection with both the Special Primary and Special General on September 18, 2024, shall file a 12-day Pre-Primary, a 12-day Pre-General and a 30-Day Post-General Report.</P>
                </SUM>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>1050 First Street NE, Washington, DC 20463.</P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Ms. Elizabeth S. Kurland, Information Division, (202) 694-1100 or (800) 424-9530, 
                        <E T="03">info@fec.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">Principal Campaign Committees</HD>
                <P>All principal campaign committees of candidates who participate in the New Jersey Special Primary and Special General Election shall file a 12-day Pre-Primary Report on July 4, 2024; a 12-day Pre-General Report on September 6, 2024, and a 30-day Post-General Report on October 18, 2024. (See charts below for the closing date for each report.)</P>
                <P>Note that these reports are in addition to the campaign committee's regular quarterly filings. (See charts below for the closing date for each report.)</P>
                <HD SOURCE="HD1">Unauthorized Committees (PACs and Party Committees)</HD>
                <P>Political committees not filing monthly are subject to special election reporting if they make previously undisclosed contributions or expenditures in connection with the New Jersey Special Primary or Special General Election by the close of books for the applicable report(s). (See charts below for the closing date for each report.)</P>
                <P>Committees filing monthly that make contributions or expenditures in connection with the New Jersey Special Primary or Special General Election will continue to file according to the monthly reporting schedule.</P>
                <P>
                    Additional disclosure information for the New Jersey special elections may be found on the FEC website at 
                    <E T="03">https://www.fec.gov/help-candidates-and-committees/dates-and-deadlines/.</E>
                </P>
                <HD SOURCE="HD1">Disclosure of Lobbyist Bundling Activity</HD>
                <P>
                    Principal campaign committees, party committees and leadership PACs that are otherwise required to file reports in connection with the special elections must simultaneously file FEC Form 3L if they receive two or more bundled contributions from lobbyists/registrants or lobbyist/registrant PACs that aggregate in excess of $22,700 during the special election reporting periods. (See charts below for closing date of each period.) 11 CFR 104.22(a)(5)(v), (b), 110.17(e)(2), (f).
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>1</SU>
                         The reporting period always begins the day after the closing date of the last report filed. If the committee is new and has not previously filed a report, the first report must cover all activity that occurred before the committee registered as a political committee up through the close of books for the first report due.
                    </P>
                    <P>
                        <SU>2</SU>
                         Notice that this filing deadline falls on a weekend or federal holiday. Filing deadlines are not extended when they fall on nonworking days. Accordingly, reports filed by methods other than registered, certified or overnight mail, or electronically, must be received before the Commission's close of business on the last business day before the deadline.
                    </P>
                </FTNT>
                <GPOTABLE COLS="4" OPTS="L2,i1" CDEF="s50,12,12,12">
                    <TTITLE>Calendar of Reporting Dates for New Jersey Special Elections</TTITLE>
                    <BOXHD>
                        <CHED H="1">Report</CHED>
                        <CHED H="1">
                            Close of books 
                            <SU>1</SU>
                        </CHED>
                        <CHED H="1">
                            Reg./Cert. &amp; overnight filing mailing
                            <LI>deadline</LI>
                        </CHED>
                        <CHED H="1">Filing deadline</CHED>
                    </BOXHD>
                    <ROW EXPSTB="03" RUL="s">
                        <ENT I="21">
                            <E T="02">Political Committees Involved in</E>
                              
                            <E T="0714">Only</E>
                              
                            <E T="02">the Special Primary (07/16/2024) Must File:</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Pre-Primary</ENT>
                        <ENT>06/26/2024</ENT>
                        <ENT>07/01/2024</ENT>
                        <ENT>
                            <SU>2</SU>
                             07/04/2024
                        </ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">July Quarterly</ENT>
                        <ENT>06/30/2024</ENT>
                        <ENT>07/15/2024</ENT>
                        <ENT>07/15/2024</ENT>
                    </ROW>
                    <ROW EXPSTB="03" RUL="s">
                        <ENT I="21">
                            <E T="02">Political Committees Involved in Both the Special Primary (07/16/2024) and Special General (09/18/2024) Must File:</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Pre-Primary</ENT>
                        <ENT>06/26/2024</ENT>
                        <ENT>07/01/2024</ENT>
                        <ENT>
                            <SU>2</SU>
                             07/04/2024
                        </ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">July Quarterly</ENT>
                        <ENT>06/30/2024</ENT>
                        <ENT>07/15/2024</ENT>
                        <ENT>07/15/2024</ENT>
                    </ROW>
                    <ROW RUL="n,s">
                        <ENT I="01">Pre-General</ENT>
                        <ENT>08/29/2024</ENT>
                        <ENT>09/03/2024</ENT>
                        <ENT>09/06/2024</ENT>
                    </ROW>
                    <ROW RUL="n,s">
                        <ENT I="01">October Quarterly</ENT>
                        <ENT A="02">WAIVED</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Post-General</ENT>
                        <ENT>10/08/2024</ENT>
                        <ENT>10/18/2024</ENT>
                        <ENT>10/18/2024</ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">Year-End</ENT>
                        <ENT>12/31/2024</ENT>
                        <ENT>01/31/2025</ENT>
                        <ENT>01/31/2025</ENT>
                    </ROW>
                    <ROW EXPSTB="03" RUL="s">
                        <ENT I="21">
                            <E T="02">Political Committees Involved in</E>
                              
                            <E T="0714">Only</E>
                              
                            <E T="02">the Special General (09/18/2024) Must File:</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00" RUL="n,s">
                        <ENT I="01">Pre-General</ENT>
                        <ENT>08/29/2024</ENT>
                        <ENT>09/03/2024</ENT>
                        <ENT>09/06/2024</ENT>
                    </ROW>
                    <ROW RUL="n,s">
                        <ENT I="01">October Quarterly</ENT>
                        <ENT A="02">WAIVED</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Post-General</ENT>
                        <ENT>10/08/2024</ENT>
                        <ENT>10/18/2024</ENT>
                        <ENT>10/18/2024</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Year-End</ENT>
                        <ENT>12/31/2024</ENT>
                        <ENT>01/31/2025</ENT>
                        <ENT>01/31/2025</ENT>
                    </ROW>
                </GPOTABLE>
                <SIG>
                    <PRTPAGE P="41967"/>
                    <P>On behalf of the Commission.</P>
                    <DATED>Dated: May 9, 2024.</DATED>
                    <NAME>Sean J. Cooksey,</NAME>
                    <TITLE>Chairman, Federal Election Commission.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10501 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 6715-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">FEDERAL MARITIME COMMISSION</AGENCY>
                <DEPDOC>[Docket No. 24-19]</DEPDOC>
                <SUBJECT>Peloton Interactive, Inc., Complainant v. Flexport International LLC, Respondent; Served: May 8, 2024; Notice of Filing of Complaint and Assignment</SUBJECT>
                <P>
                    Notice is given that a complaint has been filed with the Federal Maritime Commission (the “Commission”) by Peloton Interactive, Inc. (the “Complainant”) against Flexport International LLC (the “Respondent”). Complainant states that the Commission has subject matter jurisdiction over the complaint pursuant to the Shipping Act of 1984, as amended, 46 U.S.C. 40101 
                    <E T="03">et seq.</E>
                     and personal jurisdiction over the Respondent as a non-vessel-operating common carrier, as defined in 46 U.S.C. 40102(17).
                </P>
                <P>Complainant is a Delaware corporation with its corporate headquarters in New York, New York.</P>
                <P>Complainant identifies Respondent as an entity organized under the laws of the state of Delaware with a principal place of business in San Fransisco, California.</P>
                <P>Complainant alleges that Respondent violated 46 U.S.C. 41102(c), 41104(a)(14), and 41104(a)(15) and 46 CFR 545.4 and 545.5. Complainant alleges these violations arose from a failure to properly perform and a delay in performance of inland transportation obligations on store door shipments, and other acts and omissions of the Respondent, that resulted in damages, such as unreasonable costs, demurrage and detention charges, and delay.</P>
                <P>An answer to the complaint must be filed with the Commission within 25 days after the date of service.</P>
                <P>
                    The full text of the complaint can be found in the Commission's electronic Reading Room at 
                    <E T="03">https://www2.fmc.gov/readingroom/proceeding/24-19/.</E>
                     This proceeding has been assigned to the Office of Administrative Law Judges. The initial decision of the presiding judge shall be issued by May 8, 2025, and the final decision of the Commission shall be issued by November 24, 2025.
                </P>
                <SIG>
                    <NAME>David Eng,</NAME>
                    <TITLE>Secretary.</TITLE>
                </SIG>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10433 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 6730-02-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF HEALTH AND HUMAN SERVICES</AGENCY>
                <SUBAGY>Centers for Medicare &amp; Medicaid Services</SUBAGY>
                <DEPDOC>[Document Identifiers: CMS-10123/10124]</DEPDOC>
                <SUBJECT>Agency Information Collection Activities: Proposed Collection; Comment Request</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Centers for Medicare &amp; Medicaid Services, Health and Human Services (HHS).</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>
                        The Centers for Medicare &amp; Medicaid Services (CMS) is announcing an opportunity for the public to comment on CMS' intention to collect information from the public. Under the Paperwork Reduction Act of 1995 (PRA), federal agencies are required to publish notice in the 
                        <E T="04">Federal Register</E>
                         concerning each proposed collection of information (including each proposed extension or reinstatement of an existing collection of information) and to allow 60 days for public comment on the proposed action. Interested persons are invited to send comments regarding our burden estimates or any other aspect of this collection of information, including the necessity and utility of the proposed information collection for the proper performance of the agency's functions, the accuracy of the estimated burden, ways to enhance the quality, utility, and clarity of the information to be collected, and the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
                    </P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Comments must be received by July 15, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>When commenting, please reference the document identifier or OMB control number. To be assured consideration, comments and recommendations must be submitted in any one of the following ways:</P>
                    <P>
                        1. 
                        <E T="03">Electronically.</E>
                         You may send your comments electronically to 
                        <E T="03">http://www.regulations.gov.</E>
                         Follow the instructions for “Comment or Submission” or “More Search Options” to find the information collection document(s) that are accepting comments.
                    </P>
                    <P>
                        2. 
                        <E T="03">By regular mail.</E>
                         You may mail written comments to the following address: CMS, Office of Strategic Operations and Regulatory Affairs, Division of Regulations Development, Attention: Document Identifier/OMB Control Number:  __, Room C4-26-05, 7500 Security Boulevard, Baltimore, Maryland 21244-1850.
                    </P>
                    <P>
                        To obtain copies of a supporting statement and any related forms for the proposed collection(s) summarized in this notice, please access the CMS PRA website by copying and pasting the following web address into your web browser: 
                        <E T="03">https://www.cms.gov/Regulations-and-Guidance/Legislation/PaperworkReductionActof1995/PRA-Listing.</E>
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>William N. Parham at (410) 786-4669.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">Contents</HD>
                <P>
                    This notice sets out a summary of the use and burden associated with the following information collections. More detailed information can be found in each collection's supporting statement and associated materials (see 
                    <E T="02">ADDRESSES</E>
                    ).
                </P>
                <HD SOURCE="HD1">CMS-10123/10124 Fast Track Appeals Notices: NOMNC/DENC</HD>
                <P>
                    Under the PRA (44 U.S.C. 3501-3520), federal agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. The term “collection of information” is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c) and includes agency requests or requirements that members of the public submit reports, keep records, or provide information to a third party. Section 3506(c)(2)(A) of the PRA requires federal agencies to publish a 60-day notice in the 
                    <E T="04">Federal Register</E>
                     concerning each proposed collection of information, including each proposed extension or reinstatement of an existing collection of information, before submitting the collection to OMB for approval. To comply with this requirement, CMS is publishing this notice.
                </P>
                <HD SOURCE="HD1">Information Collection</HD>
                <P>
                    1. 
                    <E T="03">Type of Information Collection Request:</E>
                     Revision of a currently approved collection; 
                    <E T="03">Title of Information Collection:</E>
                     Fast Track Appeals Notices: NOMNC/DENC; 
                    <E T="03">Use:</E>
                     The purpose of the NOMNC is to help a beneficiary/enrollee decide whether to pursue a fast appeal by a Quality Improvement Organization (QIO) and informs them on how to file a request. 
                    <PRTPAGE P="41968"/>
                    Consistent with §§ 405.1200 and 422.624, SNFs, HHAs, CORFs, and hospices must provide notice to all beneficiaries/enrollees whose Medicare-covered services are ending, no later than two days in advance of the proposed termination of service. This information is conveyed to the beneficiary/enrollee via the NOMNC.
                </P>
                <P>
                    If a beneficiary/enrollee appeals the termination decision, the beneficiary/enrollee and the QIO, consistent with §§ 405.1200(b) and 405.1202(f) for Traditional Medicare, and §§ 422.624(b) and 422.626(e)(1)-(5) for MA plans, will receive a detailed explanation of the reasons services should end. This detailed explanation is provided to the beneficiary/enrollee using the DENC, the second notice included in this renewal package. 
                    <E T="03">Form Number:</E>
                     CMS-10123/10124 (OMB control number: 0938-0935); 
                    <E T="03">Frequency:</E>
                     Yearly; 
                    <E T="03">Affected Public:</E>
                     Private sector, Business or other for-profits and Not-for-profit institutions; 
                    <E T="03">Number of Respondents:</E>
                     32,384; 
                    <E T="03">Number of Responses:</E>
                     21,322,379; 
                    <E T="03">Total Annual Hours:</E>
                     3,962,194. (For policy questions regarding this collection contact Janet Miller at 
                    <E T="03">janet.miller@cms.hhs.gov.</E>
                    )
                </P>
                <SIG>
                    <NAME>William N. Parham, III</NAME>
                    <TITLE>Director, Division of Information Collections and Regulatory Impacts, Office of Strategic Operations and Regulatory Affairs.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10545 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4120-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HEALTH AND HUMAN SERVICES</AGENCY>
                <SUBAGY>Centers for Medicare &amp; Medicaid Services</SUBAGY>
                <DEPDOC>[Document Identifiers: CMS-10110]</DEPDOC>
                <SUBJECT>Agency Information Collection Activities: Submission for OMB Review; Comment Request</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Centers for Medicare &amp; Medicaid Services, Health and Human Services (HHS).</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>
                        The Centers for Medicare &amp; Medicaid Services (CMS) is announcing an opportunity for the public to comment on CMS' intention to collect information from the public. Under the Paperwork Reduction Act of 1995 (PRA), federal agencies are required to publish notice in the 
                        <E T="04">Federal Register</E>
                         concerning each proposed collection of information, including each proposed extension or reinstatement of an existing collection of information, and to allow a second opportunity for public comment on the notice. Interested persons are invited to send comments regarding the burden estimate or any other aspect of this collection of information, including the necessity and utility of the proposed information collection for the proper performance of the agency's functions, the accuracy of the estimated burden, ways to enhance the quality, utility, and clarity of the information to be collected, and the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
                    </P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Comments on the collection(s) of information must be received by the OMB desk officer by June 13, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Written comments and recommendations for the proposed information collection should be sent within 30 days of publication of this notice to 
                        <E T="03">www.reginfo.gov/public/do/PRAMain</E>
                        . Find this particular information collection by selecting “Currently under 30-day Review—Open for Public Comments” or by using the search function.
                    </P>
                    <P>
                        To obtain copies of a supporting statement and any related forms for the proposed collection(s) summarized in this notice, please access the CMS PRA website by copying and pasting the following web address into your web browser: 
                        <E T="03">https://www.cms.gov/Regulations-and-Guidance/Legislation/PaperworkReductionActof1995/PRA-Listing.</E>
                        .
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>William Parham at (410) 786-4669.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    Under the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3501-3520), federal agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. The term “collection of information” is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c) and includes agency requests or requirements that members of the public submit reports, keep records, or provide information to a third party. Section 3506(c)(2)(A) of the PRA (44 U.S.C. 3506(c)(2)(A)) requires federal agencies to publish a 30-day notice in the 
                    <E T="04">Federal Register</E>
                     concerning each proposed collection of information, including each proposed extension or reinstatement of an existing collection of information, before submitting the collection to OMB for approval. To comply with this requirement, CMS is publishing this notice that summarizes the following proposed collection(s) of information for public comment:
                </P>
                <P>
                    1. 
                    <E T="03">Type of Information Collection Request:</E>
                     Revision of currently approved collection; 
                    <E T="03">Title of Information Collection:</E>
                     Manufacturer Submission of Average Sales Price (ASP) Data for Medicare Part B Drugs and Biologicals; 
                    <E T="03">Use:</E>
                     Section 1847A of the Act requires that the Medicare Part B payment amounts for covered drugs and biologicals not paid on a cost or prospective payment basis be based upon manufacturers' average sales price data submitted quarterly to the Centers for Medicare &amp; Medicaid Services (CMS). The reporting requirements are specified in 42 CFR part 414 Subpart J.
                </P>
                <P>
                    CMS, specifically, the Division of Data Analysis and Market-based Pricing (DDAMBP) will utilize the ASP data (ASP and number of units sold as specific in section 1847A of the Act) to determine the Medicare Part B drug payment amounts for CY 2005 and beyond. The manufacturers submit their ASP data for all of their National Drug Codes (NDC) for Part B drugs. DDAMBP compiles the data, analyzes the data and runs the data through software to calculate the volume-weighted ASP for all of the NDCs that are grouped within a given HCPCS code. The formula to calculate the volume-weighted ASP is the Sum (ASP * units) for all NDCs/Sum (units * bill units per pkg) for all NDCs. DDAMBP provides ASP payment amounts for several components within CMS that utilize 1847(A) payment methodologies to implement various payment policies including, but not limited to, ESRD, OPPS, OTP and payment models. CMS will also use reported ASP and units to calculate inflation adjusted coinsurance and rebates. The Department of Health and Human Services' Office of the Inspector General also uses the ASP data in conducting studies. 
                    <E T="03">Form Number:</E>
                     CMS-10110 (OMB Control Number: 0938-0921); 
                    <E T="03">Frequency:</E>
                     Quarterly; 
                    <E T="03">Affected Public:</E>
                     Private and Business or other for-profits; 
                    <E T="03">Number of Respondents:</E>
                     500; 
                    <E T="03">Number of Responses:</E>
                     2,00; 
                    <E T="03">Total Annual Hours:</E>
                     26,000. (For policy questions regarding this collection contact Felicia Brown at (410) 786-9287 or 
                    <E T="03">Felicia.brown@cms.hhs.gov</E>
                    ).
                </P>
                <SIG>
                    <NAME>William N. Parham, III,</NAME>
                    <TITLE>Director, Division of Information Collections and Regulatory Impacts, Office of Strategic Operations and Regulatory Affairs.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10541 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4120-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <PRTPAGE P="41969"/>
                <AGENCY TYPE="S">DEPARTMENT OF HEALTH AND HUMAN SERVICES</AGENCY>
                <SUBAGY>National Institutes of Health</SUBAGY>
                <SUBJECT>Center for Scientific Review; Notice of Closed Meetings</SUBJECT>
                <P>Pursuant to section 1009 of the Federal Advisory Committee Act, as amended, notice is hereby given of the following meetings.</P>
                <P>The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.</P>
                <EXTRACT>
                    <P>
                        <E T="03">Name of Committee:</E>
                         Center for Scientific Review Special Emphasis Panel; Member Conflict: Respiratory Sciences.
                    </P>
                    <P>
                        <E T="03">Date:</E>
                         June 12, 2024.
                    </P>
                    <P>
                        <E T="03">Time:</E>
                         10:00 a.m. to 6:30 p.m.
                    </P>
                    <P>
                        <E T="03">Agenda:</E>
                         To review and evaluate grant applications.
                    </P>
                    <P>
                        <E T="03">Place:</E>
                         National Institutes of Health, Rockledge II, 6701 Rockledge Drive, Bethesda, MD 20892.
                    </P>
                    <P>
                        <E T="03">Meeting Format:</E>
                         Virtual Meeting.
                    </P>
                    <P>
                        <E T="03">Contact Person:</E>
                         Imoh S Okon, Ph.D., Scientific Review Officer, Center for Scientific Review, National Institutes of Health, 6701 Rockledge Drive, Bethesda, MD 20817, 301-347-8881, 
                        <E T="03">imoh.okon@nih.gov.</E>
                    </P>
                    <P>
                        <E T="03">Name of Committee:</E>
                         Endocrinology, Metabolism, Nutrition and Reproductive Sciences Integrated Review Group; Basic Mechanisms of Diabetes and Metabolism Study Section.
                    </P>
                    <P>
                        <E T="03">Date:</E>
                         June 12-13, 2024.
                    </P>
                    <P>
                        <E T="03">Time:</E>
                         10:00 a.m. to 6:00 p.m.
                    </P>
                    <P>
                        <E T="03">Agenda:</E>
                         To review and evaluate grant applications.
                    </P>
                    <P>
                        <E T="03">Place:</E>
                         National Institutes of Health, Rockledge II, 6701 Rockledge Drive, Bethesda, MD 20892.
                    </P>
                    <P>
                        <E T="03">Meeting Format:</E>
                         Virtual Meeting.
                    </P>
                    <P>
                        <E T="03">Contact Person:</E>
                         Baskaran Thyagarajan, Ph.D., Scientific Review Officer, Center for Scientific Review, National Institutes of Health, 6701 Rockledge Drive, Room 800B, Bethesda, MD 20892, (301) 594-0331, 
                        <E T="03">baski.thyagarajan@nih.gov.</E>
                    </P>
                    <P>
                        <E T="03">Name of Committee:</E>
                         Bioengineering Sciences &amp; Technologies Integrated Review Group; Biomaterials and Biointerfaces Study Section.
                    </P>
                    <P>
                        <E T="03">Date:</E>
                         June 13-14, 2024.
                    </P>
                    <P>
                        <E T="03">Time:</E>
                         8:00 a.m. to 6:00 p.m.
                    </P>
                    <P>
                        <E T="03">Agenda:</E>
                         To review and evaluate grant applications.
                    </P>
                    <P>
                        <E T="03">Place:</E>
                         The Bethesdan Hotel, 8120 Wisconsin Avenue, Bethesda, MD 20814.
                    </P>
                    <P>
                        <E T="03">Meeting Format:</E>
                         In Person.
                    </P>
                    <P>
                        <E T="03">Contact Person:</E>
                         Jennifer Fiori O'Connell, Ph.D., Scientific Review Officer, The Center for Scientific Review, The National Institutes of Health, 6701 Rockledge Drive, Bethesda, MD 20892, (410) 454-8478, 
                        <E T="03">jennifer.oconnell@nih.gov.</E>
                    </P>
                    <P>
                        <E T="03">Name of Committee:</E>
                         Digestive, Kidney and Urological Systems Integrated Review Group; Digestive and Nutrient Physiology and Diseases Study Section.
                    </P>
                    <P>
                        <E T="03">Date:</E>
                         June 13-14, 2024.
                    </P>
                    <P>
                        <E T="03">Time:</E>
                         8:30 a.m. to 8:00 p.m.
                    </P>
                    <P>
                        <E T="03">Agenda:</E>
                         To review and evaluate grant applications.
                    </P>
                    <P>
                        <E T="03">Place:</E>
                         National Institutes of Health, Rockledge II, 6701 Rockledge Drive, Bethesda, MD 20892.
                    </P>
                    <P>
                        <E T="03">Meeting Format:</E>
                         In Person and Virtual Meeting.
                    </P>
                    <P>
                        <E T="03">Contact Person:</E>
                         Aster Juan, Ph.D., Scientific Review Officer, Center for Scientific Review, National Institutes of Health, 6701 Rockledge Drive, Bethesda, MD 20817, 301-435-5000, 
                        <E T="03">juana2@mail.nih.gov.</E>
                    </P>
                    <P>
                        <E T="03">Name of Committee:</E>
                         Center for Scientific Review Special Emphasis Panel PAR Panel; Research on Current Topics in Alzheimer's Disease and its Related Dementias.
                    </P>
                    <P>
                        <E T="03">Date:</E>
                         June 13-14, 2024.
                    </P>
                    <P>
                        <E T="03">Time:</E>
                         9:00 a.m. to 7:00 p.m.
                    </P>
                    <P>
                        <E T="03">Agenda:</E>
                         To review and evaluate grant applications.
                    </P>
                    <P>
                        <E T="03">Place:</E>
                         Hilton Garden Inn, Washington DC/Georgetown, 2201 M Street NW, Washington, DC 20037.
                    </P>
                    <P>
                        <E T="03">Meeting Format:</E>
                         In Person.
                    </P>
                    <P>
                        <E T="03">Contact Person:</E>
                         Ashley Marie Kopec, Ph.D., Scientific Review Officer, Center for Scientific Review, National Institutes of Health, 6701 Rockledge Drive, Bethesda, MD 20892, (301) 496-9293, 
                        <E T="03">kopecam@csr.nih.gov.</E>
                    </P>
                    <P>
                        <E T="03">Name of Committee:</E>
                         Surgical Sciences, Biomedical Imaging and Bioengineering Integrated Review Group; Imaging Guided Interventions and Surgery Study Section.
                    </P>
                    <P>
                        <E T="03">Date:</E>
                         June 13-14, 2024.
                    </P>
                    <P>
                        <E T="03">Time:</E>
                         9:00 a.m. to 8:00 p.m.
                    </P>
                    <P>
                        <E T="03">Agenda:</E>
                         To review and evaluate grant applications.
                    </P>
                    <P>
                        <E T="03">Place:</E>
                         National Institutes of Health, Rockledge II, 6701 Rockledge Drive, Bethesda, MD 20892.
                    </P>
                    <P>
                        <E T="03">Meeting Format:</E>
                         Virtual Meeting.
                    </P>
                    <P>
                        <E T="03">Contact Person:</E>
                         Ella Fung Jones, Ph.D., Scientific Review Officer, Center for Scientific Review, National Institutes of Health, 6701 Rockledge Drive, Bethesda, MD 20892, (301) 496-0777, 
                        <E T="03">ella.jones@nih.gov.</E>
                    </P>
                    <P>
                        <E T="03">Name of Committee:</E>
                         Surgical Sciences, Biomedical Imaging and Bioengineering Integrated Review Group; Emerging Imaging Technologies and Applications Study Section.
                    </P>
                    <P>
                        <E T="03">Date:</E>
                         June 13-14, 2024.
                    </P>
                    <P>
                        <E T="03">Time:</E>
                         9:00 a.m. to 8:00 p.m.
                    </P>
                    <P>
                        <E T="03">Agenda:</E>
                         To review and evaluate grant applications.
                    </P>
                    <P>
                        <E T="03">Place:</E>
                         National Institutes of Health, Rockledge II, 6701 Rockledge Drive, Bethesda, MD 20892.
                    </P>
                    <P>
                        <E T="03">Meeting Format:</E>
                         Virtual Meeting.
                    </P>
                    <P>
                        <E T="03">Contact Person:</E>
                         Zheng Li, Ph.D., Scientific Review Officer, Center for Scientific Review, National Institutes of Health, 6701 Rockledge Drive, Bethesda, MD 20892, (301) 594-3385, 
                        <E T="03">zheng.li3@nih.gov.</E>
                    </P>
                    <P>
                        <E T="03">Name of Committee:</E>
                         Digestive, Kidney and Urological Systems Integrated Review Group; Kidney and Urological Systems Function and Dysfunction Study Section.
                    </P>
                    <P>
                        <E T="03">Date:</E>
                         June 13-14, 2024.
                    </P>
                    <P>
                        <E T="03">Time:</E>
                         9:30 a.m. to 8:30 p.m.
                    </P>
                    <P>
                        <E T="03">Agenda:</E>
                         To review and evaluate grant applications.
                    </P>
                    <P>
                        <E T="03">Place:</E>
                         National Institutes of Health, Rockledge II, 6701 Rockledge Drive, Bethesda, MD 20892.
                    </P>
                    <P>
                        <E T="03">Meeting Format:</E>
                         In Person and Virtual Meeting.
                    </P>
                    <P>
                        <E T="03">Contact Person:</E>
                         Santanu Banerjee, Ph.D., Scientific Review Officer, Center for Scientific Review, National Institutes of Health, 6701 Rockledge Drive, Room 2106, Bethesda, MD 20892, (301) 435-5947, 
                        <E T="03">banerjees5@mail.nih.gov.</E>
                    </P>
                    <P>
                        <E T="03">Name of Committee:</E>
                         Risk, Prevention and Health Behavior Integrated Review Group; Interventions to Prevent and Treat Addictions Study Section.
                    </P>
                    <P>
                        <E T="03">Date:</E>
                         June 13-14, 2024.
                    </P>
                    <P>
                        <E T="03">Time:</E>
                         9:30 a.m. to 8:00 p.m.
                    </P>
                    <P>
                        <E T="03">Agenda:</E>
                         To review and evaluate grant applications.
                    </P>
                    <P>
                        <E T="03">Place:</E>
                         Embassy Suites at the Chevy Chase Pavilion, 4300 Military Road NW, Washington, DC 20015.
                    </P>
                    <P>
                        <E T="03">Meeting Format:</E>
                         In Person.
                    </P>
                    <P>
                        <E T="03">Contact Person:</E>
                         Izabella Zandberg, Ph.D., Scientific Review Officer, Center for Scientific Review, 6701 Rockledge Drive, Bethesda, MD 20892, 301-594-0359, 
                        <E T="03">izabella.zandberg@nih.gov.</E>
                    </P>
                    <P>
                        <E T="03">Name of Committee:</E>
                         Biological Chemistry and Macromolecular Biophysics Integrated Review Group; Macromolecular Structure and Function C Study Section.
                    </P>
                    <P>
                        <E T="03">Date:</E>
                         June 13-14, 2024.
                    </P>
                    <P>
                        <E T="03">Time:</E>
                         10:00 a.m. to 8:00 p.m.
                    </P>
                    <P>
                        <E T="03">Agenda:</E>
                         To review and evaluate grant applications.
                    </P>
                    <P>
                        <E T="03">Place:</E>
                         National Institutes of Health, Rockledge II, 6701 Rockledge Drive, Bethesda, MD 20892.
                    </P>
                    <P>
                        <E T="03">Meeting Format:</E>
                         Virtual Meeting.
                    </P>
                    <P>
                        <E T="03">Contact Person:</E>
                         Guillermo Andres Bermejo, Ph.D., Scientific Review Officer, The Center for Scientific Review, The National Institutes of Health, 6701 Rockledge Drive, Bethesda, MD 20892, (301) 827-5742, 
                        <E T="03">bermejog@mail.nih.gov.</E>
                    </P>
                    <FP>(Catalogue of Federal Domestic Assistance Program Nos. 93.306, Comparative Medicine; 93.333, Clinical Research, 93.306, 93.333, 93.337, 93.393-93.396, 93.837-93.844, 93.846-93.878, 93.892, 93.893, National Institutes of Health, HHS)</FP>
                </EXTRACT>
                <SIG>
                    <DATED>Dated: May 9, 2024.</DATED>
                    <NAME>Melanie J. Pantoja,</NAME>
                    <TITLE>Program Analyst, Office of Federal Advisory Committee Policy.</TITLE>
                </SIG>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10511 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4140-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <PRTPAGE P="41970"/>
                <AGENCY TYPE="S">DEPARTMENT OF HEALTH AND HUMAN SERVICES</AGENCY>
                <SUBAGY>National Institutes of Health</SUBAGY>
                <SUBJECT>National Institute of Neurological Disorders and Stroke; Notice of Closed Meeting</SUBJECT>
                <P>Pursuant to section 1009 of the Federal Advisory Committee Act, as amended, notice is hereby given of the following meeting.</P>
                <P>The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.</P>
                <EXTRACT>
                    <P>
                        <E T="03">Name of Committee:</E>
                         Neurological Sciences Training Initial Review Group; NST-2 Study Section NINDS K99 and K01.
                    </P>
                    <P>
                        <E T="03">Date:</E>
                         June 3-4, 2024.
                    </P>
                    <P>
                        <E T="03">Time:</E>
                         9:00 a.m. to 6:00 p.m.
                    </P>
                    <P>
                        <E T="03">Agenda:</E>
                         To review and evaluate grant applications.
                    </P>
                    <P>
                        <E T="03">Place:</E>
                         Hilton Alexandria Old Town, 1767 King Street, Alexandria, VA 22314.
                    </P>
                    <P>
                        <E T="03">Contact Person:</E>
                         DeAnna Lynn Adkins, Ph.D., Scientific Review Officer, Scientific Review Branch, Division of Extramural Activities, NINDS/NIH/HHS, NSC, 6001 Executive Boulevard, Rockville, MD 20852, 301-496-9223, 
                        <E T="03">deanna.adkins@nih.gov.</E>
                    </P>
                    <FP>(Catalogue of Federal Domestic Assistance Program Nos. 93.853, Clinical Research Related to Neurological Disorders; 93.854, Biological Basis Research in the Neurosciences, National Institutes of Health, HHS).</FP>
                </EXTRACT>
                <SIG>
                    <DATED>Dated: May 9, 2024.</DATED>
                    <NAME>Lauren A. Fleck,</NAME>
                    <TITLE>Program Analyst, Office of Federal Advisory Committee Policy.</TITLE>
                </SIG>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10521 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4140-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HEALTH AND HUMAN SERVICES</AGENCY>
                <SUBAGY>National Institutes of Health</SUBAGY>
                <SUBJECT>National Institute on Aging; Notice of Closed Meeting</SUBJECT>
                <P>Pursuant to section 1009 of the Federal Advisory Committee Act, as amended, notice is hereby given of the following meeting.</P>
                <P>The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.</P>
                <EXTRACT>
                    <P>
                        <E T="03">Name of Committee:</E>
                         National Institute on Aging Special Emphasis Panel; APOE as a Mediator of Fuel Metabolism and AD Risk.
                    </P>
                    <P>
                        <E T="03">Date:</E>
                         July 31, 2024.
                    </P>
                    <P>
                        <E T="03">Time:</E>
                         11:30 a.m. to 5:00 p.m.
                    </P>
                    <P>
                        <E T="03">Agenda:</E>
                         To review and evaluate grant applications.
                    </P>
                    <P>
                        <E T="03">Place:</E>
                         National Institute on Aging, Gateway Building, 7201 Wisconsin Avenue, Bethesda, MD 20892 (Virtual Meeting).
                    </P>
                    <P>
                        <E T="03">Contact Person:</E>
                         Nesar Uddin Akanda, M.D., Ph.D.,  Scientific Review Officer, Scientific Review Branch, National Institute on Aging, 7201 Wisconsin Avenue, Gateway Bldg., Room 2E405, Bethesda, MD 20814, (301) 594-8984, 
                        <E T="03">nesar.akanda@nih.gov.</E>
                    </P>
                    <FP>(Catalogue of Federal Domestic Assistance Program Nos. 93.866, Aging Research, National Institutes of Health, HHS)</FP>
                </EXTRACT>
                <SIG>
                    <DATED>Dated: May 8, 2024. </DATED>
                    <NAME>Miguelina Perez,</NAME>
                    <TITLE>Program Analyst, Office of Federal Advisory Committee Policy.</TITLE>
                </SIG>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10495 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4140-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HEALTH AND HUMAN SERVICES</AGENCY>
                <SUBAGY>National Institutes of Health</SUBAGY>
                <SUBJECT>National Institute on Aging; Notice of Closed Meeting</SUBJECT>
                <P>Pursuant to section 1009 of the Federal Advisory Committee Act, as amended, notice is hereby given of the following meeting.</P>
                <P>The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.</P>
                <EXTRACT>
                    <P>
                        <E T="03">Name of Committee:</E>
                         National Institute on Aging Special Emphasis Panel; Targeting Sleep to Prevent Alzheimer's Disease.
                    </P>
                    <P>
                        <E T="03">Date:</E>
                         July 10, 2024.
                    </P>
                    <P>
                        <E T="03">Time:</E>
                         11:30 a.m. to 5:00 p.m.
                    </P>
                    <P>
                        <E T="03">Agenda:</E>
                         To review and evaluate grant applications.
                    </P>
                    <P>
                        <E T="03">Place:</E>
                         National Institute on Aging, Gateway Building, 7201 Wisconsin Avenue, Bethesda, MD 20892 (Virtual Meeting).
                    </P>
                    <P>
                        <E T="03">Contact Person:</E>
                         Nesar Uddin Akanda, M.D., Ph.D.,  Scientific Review Officer, Scientific Review Branch, National Institute on Aging, 7201 Wisconsin Avenue, Gateway Bldg., Room 2E405,  Bethesda, MD 20814, (301) 594-8984, 
                        <E T="03">nesar.akanda@nih.gov.</E>
                    </P>
                    <FP>(Catalogue of Federal Domestic Assistance Program Nos. 93.866, Aging Research, National Institutes of Health, HHS)</FP>
                </EXTRACT>
                <SIG>
                    <DATED>Dated: May 8, 2024. </DATED>
                    <NAME>Miguelina Perez,</NAME>
                    <TITLE>Program Analyst, Office of Federal Advisory Committee Policy.</TITLE>
                </SIG>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10497 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4140-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HEALTH AND HUMAN SERVICES</AGENCY>
                <SUBAGY>National Institutes of Health</SUBAGY>
                <SUBJECT>National Institute of General Medical Sciences; Notice of Closed Meeting</SUBJECT>
                <P>Pursuant to section 1009 of the Federal Advisory Committee Act, as amended, notice is hereby given of the following meeting.</P>
                <P>The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.</P>
                <EXTRACT>
                    <P>
                        <E T="03">Name of Committee:</E>
                         National Institute of General Medical Sciences Special Emphasis Panel; Review of the Centers of Biomedical Research Excellence (COBRE) Phase 1.
                    </P>
                    <P>
                        <E T="03">Date:</E>
                         July 25-26, 2024.
                    </P>
                    <P>
                        <E T="03">Time:</E>
                         10:00 a.m. to 6:00 p.m.
                    </P>
                    <P>
                        <E T="03">Agenda:</E>
                         To review and evaluate grant applications.
                    </P>
                    <P>
                        <E T="03">Place:</E>
                         National Institutes of Health, National Institute of General Medical Sciences, Natcher Building, 45 Center Drive, Bethesda, Maryland 20892 (Virtual Meeting).
                    </P>
                    <P>
                        <E T="03">Contact Person:</E>
                         John J. Laffan, Ph.D., Scientific Review Officer, Office of Scientific Review, National Institute of General Medical Sciences, National Institutes of Health, Natcher Building, 45 Center Drive, Room 3AN18J, Bethesda, Maryland 20892, 301-594-2773, 
                        <E T="03">laffanjo@mail.nih.gov.</E>
                    </P>
                    <FP>(Catalogue of Federal Domestic Assistance Program No. 93.859, Biomedical Research and Research Training, National Institutes of Health, HHS)</FP>
                </EXTRACT>
                <SIG>
                    <DATED>Dated: May 8, 2024.</DATED>
                    <NAME>Miguelina Perez,</NAME>
                    <TITLE>Program Analyst, Office of Federal Advisory Committee Policy.</TITLE>
                </SIG>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10496 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4140-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <PRTPAGE P="41971"/>
                <AGENCY TYPE="N">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>U.S. Customs and Border Protection</SUBAGY>
                <SUBJECT>Notice of Issuance of Final Determination Concerning Battery-Electric Semi-Trucks</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>U.S. Customs and Border Protection, Department of Homeland Security.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of final determination.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This document provides notice that U.S. Customs and Border Protection (CBP) has issued a final determination concerning the country of origin of Nikola's Tre Bev, class 8, battery-electric semi-truck. Based upon the facts presented, CBP has concluded that various imported components do undergo a substantial transformation in the United States when assembled into the battery-electric semi-truck.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>
                        The final determination was issued on May 8, 2024. A copy of the final determination is attached. Any party-at-interest, as defined in 19 CFR 177.22(d), may seek judicial review of this final determination no later than within 30 days of publication of this determination in the 
                        <E T="04">Federal Register</E>
                        .
                    </P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Ani Mard, Valuation and Special Programs Branch, Regulations and Rulings, Office of Trade, at (202) 325-0737.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>Notice is hereby given that on May 8, 2024, U.S. Customs and Border Protection (CBP) issued a final determination concerning the country of origin of Nikola's Tre Bev, class 8, battery-electric semi-truck for purposes of title III of the Trade Agreements Act of 1979. This final determination, HQ H335387, was issued at the request of Carter Machinery Co., Inc., under procedures set forth at 19 CFR part 177, subpart B, which implements title III of the Trade Agreements Act of 1979, as amended (19 U.S.C. 2511-18). In the final determination, CBP has concluded that, based upon the facts presented, the various imported components do undergo a substantial transformation in the United States when assembled into the battery-electric semi-truck.</P>
                <P>
                    Section 177.29, CBP Regulations (19 CFR 177.29), provides that a notice of final determination shall be published in the 
                    <E T="04">Federal Register</E>
                     within 60 days of the date the final determination is issued. Section 177.30, CBP Regulations (19 CFR 177.30), provides that any party-at-interest, as defined in 19 CFR 177.22(d), may seek judicial review of a final determination within 30 days of publication of such determination in the 
                    <E T="04">Federal Register</E>
                    .
                </P>
                <SIG>
                    <NAME>Alice A. Kipel,</NAME>
                    <TITLE>Executive Director, Regulations and Rulings, Office of Trade.</TITLE>
                </SIG>
                <HD SOURCE="HD3">HQ H335387</HD>
                <HD SOURCE="HD3">May 8, 2024</HD>
                <FP SOURCE="FP-1">OT:RR:CTF:VS H335387 a.m.</FP>
                <FP SOURCE="FP-1">CATEGORY: Origin</FP>
                <FP SOURCE="FP-1">Aaron Sullivan</FP>
                <P>Carter Machinery Co., Inc. 1330 Lynchburg Turnpike, Salem, VA 24153</P>
                <FP SOURCE="FP-2">RE: U.S. Government Procurement; Title III, Trade Agreements Act of 1979 (19 U.S.C. 2511); subpart B, part 177, CBP Regulations; Country of Origin of Battery-Electric Semi-Truck.</FP>
                <P>Dear Mr. Sullivan:</P>
                <P>
                    This is in response to your request, dated November 1, 2023, on behalf of Carter Machinery Co., Inc. (“Carter Machinery”), for a final determination concerning the country of origin of Nikola's Tre Bev, class 8, battery-electric semi-truck pursuant to Title III of the Trade Agreements Act of 1979 (“TAA”), as amended (19 U.S.C. 2511 
                    <E T="03">et seq.</E>
                    ), and subpart B of part 177, U.S. Customs and Border Protection (“CBP”) Regulations (19 CFR 177.21, 
                    <E T="03">et seq.</E>
                    ). Carter Machinery is a party-at-interest within the meaning of 19 CFR 177.22(d)(1) and 177.23(a) and is therefore entitled to request this final determination.
                </P>
                <HD SOURCE="HD3">FACTS</HD>
                <P>The merchandise at issue is Nikola's Tre Bev, class 8, battery-electric semi-truck (“Tre Bev”). The Tre Bev is a battery-electric, zero emission, heavy duty truck, with a 330-mile range. It is described as a 6x2 cab over style truck designed for short-haul regional-metro applications.</P>
                <P>In response to a request from this office for a more detailed breakdown of components, Carter Machinery submitted a bill of materials (BOM) containing the country of origin of the Tre Bev components, as well as documents illustrating the assembly process. According to the submission, the Tre Bev is comprised of 1,349 individual parts. The total cost of the parts was provided, and it is indicated that 67% of that cost is represented by U.S.-made products. The trucks are built in Coolidge, AZ.</P>
                <P>The U.S. assembly process is described as follows:</P>
                <P>
                    <E T="03">Station 0:</E>
                     The chassis 
                    <SU>1</SU>
                    <FTREF/>
                     (product of Mexico) is brought inside the manufacturing plant. Based on the photograph submitted, the chassis is a black rectangular base metal structure/frame. It is imported in its “bare” form, and the mechanical components are incorporated into the frame in subsequent stations. Each chassis is loaded in the upside position onto a set of automatic guided vehicles (“AGV”).
                </P>
                <FTNT>
                    <P>
                        <SU>1</SU>
                         The term “chassis” refers to the frame of the vehicle. The chassis is the main supporting structure of the vehicle and is also described as the “skeleton.” Carter Machinery uses the terms “frame” and “chassis” interchangeably.
                    </P>
                </FTNT>
                <P>
                    <E T="03">Station 1:</E>
                     AGVs are moved from station zero to station one. Several major components and brackets are installed, including suspension brackets, cab tilt pump, rear axle alignment, air spring brackets, high voltage routing brackets, and the steering gear (product of USA).
                </P>
                <P>
                    <E T="03">Station 2:</E>
                     Pre-cut pneumatic lines (product of USA) are transported from the subassembly station to the mainline. These lines control air flow to help with steering, turning, and braking functions. The low voltage harnesses (product of Spain) are installed, which help route power from the batteries to areas that require a lower voltage to operate.
                </P>
                <P>
                    <E T="03">Station 3:</E>
                     High voltage cables are bundled and assembled. These cables are directly connected to the batteries (product of USA) and e-axle. E-motor hoses, inverter pipes, and air spring suspension are also installed. Additionally, the DCDC converter (product of USA) is installed.
                </P>
                <P>
                    <E T="03">Station 4:</E>
                     The front axle (product of USA), tag axle (product of Italy), and e-axles (product of Italy) are installed. The e-axle houses twin motors that power the vehicle.
                </P>
                <P>
                    <E T="03">Station 5:</E>
                     Station five focuses on the final preparation of the chassis. The last of the major internal support brackets, battery brackets, radiator support brackets, front under rider protection assembly, high voltage compressor, and HVAC are installed.
                </P>
                <P>
                    <E T="03">Station 6:</E>
                     The vehicle gets flipped in the truck position. The AGV is moved out of the station and the AGVs for the second half of the assembly process move into the station. The flip equipment releases the chassis back down onto the new AGV in truck position.
                </P>
                <P>
                    <E T="03">Station 7:</E>
                     The high voltage cable bundles are routed. The rear Power Distribution Unit (“PDU”) (product of Malta) is installed and connected to the rear inverter (product of USA). Simultaneously, the front PDU is installed and connected to the high voltage lines that will be connected to the batteries. The heat compressor, fuse box, and expansion tanks are connected to brake resistor lines. Thermal lines are also connected in the front.
                    <PRTPAGE P="41972"/>
                </P>
                <P>
                    <E T="03">Station 8:</E>
                     The high voltage batteries are installed using a lift assist into the individual housing units creating by the battery brackets. Additionally, two low voltage batteries are installed in a small housing under the cab to power cab functions such as instrument panel, doors, lights, etc.
                </P>
                <P>
                    <E T="03">Station 9:</E>
                     The cab is prepared to be mounted in the next station. This includes installing and securing the brackets onto which the cab will slide. Radiators, rear cargo lights, rear cameras, quick exhaust, and Tire Pressure Monitoring System (TPMS) fuse boxes are also installed.
                </P>
                <P>
                    <E T="03">Station 10:</E>
                     The cab is lifted using an overhead lift assist. The cab is married onto the support brackets installed in the previous station. The electrical harness and pneumatic connections between the cab and chassis are made. The tilt pin that allows the cab to lift is also installed here.
                </P>
                <P>
                    <E T="03">Station 11:</E>
                     The cab steps, lower side plates for batteries, fifth wheel, and mud flaps are all installed. The horn and speakers are installed to the cab. The rear inverter is also routed and connected.
                </P>
                <P>
                    <E T="03">Station 12:</E>
                     The electrical side panels, storage boxes, and side steps are installed. The wheel trim is installed on the cab tires and are then mounted to the axles. Air conditioning coolant, battery coolant, windshield wiper, and power steering fluids are filled. The chassis steps are also installed.
                </P>
                <P>
                    <E T="03">Station 13</E>
                    : Bonding checks on high voltage components like batteries, compressors, DCDC converters are done to ensure they are grounded. Unified Diagnostic Services (UDS) routines are completed. Manual service disconnects are installed, completing the battery circuits. Skid plates are installed under the batteries. Electronic Braking Software (EBS) is flashed before high voltage is brought up.
                </P>
                <P>
                    <E T="03">Station 14:</E>
                     The truck is powered on at this point in the assembly process. The e-axle and controllers are paired to the accelerator through resolver learning. Air conditioning is activated, and the odometer is reset. Additionally, the lane departure warning system is programmed.
                </P>
                <P>
                    <E T="03">Alignment:</E>
                     The front axle alignment is adjusted. Rear axle alignment and thrust angle are measured. Headlamps are adjusted. Lane departure warning and autonomous emergency brake systems are also calibrated.
                </P>
                <P>
                    <E T="03">Dyno:</E>
                     The Dyno 
                    <SU>2</SU>
                    <FTREF/>
                     confirms vehicle propulsion including acceleration/deceleration, braking, and vehicle speed sensors. The vehicle function lights, windshield wipers, and cruise control are also tested.
                </P>
                <FTNT>
                    <P>
                        <SU>2</SU>
                         A dynamometer, also known as a “dyno”, is a device that measures force, torque, or power.
                    </P>
                </FTNT>
                <HD SOURCE="HD3">ISSUE</HD>
                <P>Whether the imported components are substantially transformed when made into the Tre Bev, class 8, battery-electric semi-truck in the United States.</P>
                <HD SOURCE="HD3">LAW &amp; ANALYSIS</HD>
                <P>
                    CBP issues country of origin advisory rulings and final determinations as to whether an article is or would be a product of a designated country or instrumentality for the purpose of granting waivers of certain “Buy American” restrictions in U.S. law or practice for products offered for sale to the U.S. Government, pursuant to subpart B of part 177, 19 CFR 177.21 
                    <E T="03">et seq.,</E>
                     which implements title III, Trade Agreements Act of 1979, as amended (19 U.S.C. 2511-2518).
                </P>
                <P>CBP's authority to issue advisory rulings and final determinations is set forth in 19 U.S.C. 2515(b)(1), which states:</P>
                <EXTRACT>
                    <P>For the purposes of this subchapter, the Secretary of the Treasury shall provide for the prompt issuance of advisory rulings and final determinations on whether, under section 2518(4)(B) of this title, an article is or would be a product of a foreign country or instrumentality designated pursuant to section 2511(b) of this title.</P>
                </EXTRACT>
                <FP>Emphasis added.</FP>
                <P>The Secretary of the Treasury's authority mentioned above, along with other customs revenue functions, are delegated to CBP in the Appendix to 19 CFR part 0—Treasury Department Order No. 100-16, 68 FR 28,322 (May 23, 2003).</P>
                <P>The rule of origin set forth in 19 U.S.C. 2518(4)(B) states:</P>
                <EXTRACT>
                    <P>An article is a product of a country or instrumentality only if (i) it is wholly the growth, product, or manufacture of that country or instrumentality, or (ii) in the case of an article which consists in whole or in part of materials from another country or instrumentality, it has been substantially transformed into a new and different article of commerce with a name, character, or use distinct from that of the article or articles from which it was so transformed.</P>
                </EXTRACT>
                <P>
                    <E T="03">See also</E>
                     19 CFR 177.22(a).
                </P>
                <P>
                    In rendering advisory rulings and final determinations for purposes of U.S. Government procurement, CBP applies the provisions of subpart B of part 177 consistent with the Federal Acquisition Regulation (“FAR”). 
                    <E T="03">See</E>
                     19 CFR 177.21. In this regard, CBP recognizes that the FAR restricts the U.S. Government's purchase of products to U.S.-made or designated country end products for acquisitions subject to the TAA. 
                    <E T="03">See</E>
                     48 CFR 25.403(c)(1).
                </P>
                <P>The FAR, 48 CFR 25.003, defines “U.S.-made end product” as: </P>
                <EXTRACT>
                    <P>. . . an article that is mined, produced, or manufactured in the United States or that is substantially transformed in the United States into a new and different article of commerce with a name, character, or use distinct from that of the article or articles from which it was transformed.</P>
                </EXTRACT>
                <P>Therefore, the question presented in this final determination is whether, as a result of the operations performed in the United States, the Tre Bev is substantially transformed into a product of the United States.</P>
                <P>
                    In deciding whether the combining of parts or materials constitutes a substantial transformation, the determinative issue is the extent of the operations performed and whether the parts lose their identity and become an integral part of the new article. 
                    <E T="03">See Belcrest Linens</E>
                     v. 
                    <E T="03">United States,</E>
                     6 CIT 204 (1983), 
                    <E T="03">aff'd,</E>
                     741 F.2d 1368 (Fed. Cir. 1984). Assembly operations that are minimal or simple, as opposed to complex or meaningful, will generally not result in a substantial transformation. Factors, which may be relevant in this evaluation, may include the nature of the operation (including the number of components assembled), the number of different operations involved, and whether a significant period of time, skill, detail, and quality control are necessary for the assembly operation. 
                    <E T="03">See</E>
                     C.S.D. 80-111, C.S.D. 85-25, C.S.D. 89-110, C.S.D. 89-118, C.S.D. 90-51, and C.S.D. 90-97. If the manufacturing or combining process is a minor one, which leaves the identity of the article intact, a substantial transformation has not occurred. 
                    <E T="03">See Uniroyal, Inc.</E>
                     v. 
                    <E T="03">United States,</E>
                     3 CIT 220 (1982), 
                    <E T="03">aff'd,</E>
                     702 F.2d 1022 (Fed. Cir. 1983).
                </P>
                <P>
                    In order to determine whether a substantial transformation occurs when components of various origins are assembled into completed products, CBP considers the totality of the circumstances and makes such determinations on a case-by-case basis. The country of origin of the item's components, extent of the processing that occurs within a country, and whether such processing renders a product with a new name, character, and use are primary considerations in such cases. Additionally, factors such as the resources expended on product design and development, the extent and nature of post-assembly inspection and testing procedures, and worker skill required during the actual manufacturing process will be considered when determining whether a substantial transformation has occurred. No one factor is determinative.
                    <PRTPAGE P="41973"/>
                </P>
                <P>
                    In Headquarters Ruling Letter (“HQ”) H155115, dated May 24, 2011, CBP found that assembly in the United States of an imported glider, and other imported and U.S.-origin parts, constituted a substantial transformation into the electric vehicle, an article with a new name, character, and use. The electric vehicle was composed of 31 components, of which 14 were of U.S. origin. The assembly process in the United States was complex and time-consuming and involved a significant U.S. contribution in both parts and labor. CBP determined that the country of origin of the electric vehicles for purposes of U.S. Government procurement was the United States. 
                    <E T="03">See also</E>
                     HQ H229157, dated November 16, 2012.
                </P>
                <P>In HQ H118435, dated October 13, 2010, CBP determined the United States to be the country of origin for purposes of U.S. Government procurement for a line of electric golf and recreational vehicles. In this case, CBP found that a Chinese-origin chassis, plastic body parts and pieces of plastic trim were substantially transformed when they were assembled with U.S.-origin battery packs, motors, electronics, wiring assemblies, seats, and chargers in the United States. The vehicles were composed of approximately 53 and 62 inputs, of which between 12 and 17 inputs were U.S. components and critical in making the electric vehicle. The imported parts lost their individual identities and became integral parts of a new article possessing a new name, character, and use.</P>
                <P>In HQ H022169, dated May 2, 2008, CBP held that a mini-truck glider from India was substantially transformed when assembled in the United States with approximately 87 different components, 68 of which were of U.S. origin, to produce an electric mini-truck. CBP found that the imported glider lost its individual identity and became an integral part of a new article possessing a new name, character and use. Accordingly, CBP determined the assembly process was complex and time-consuming and involved a significant U.S. contribution, in both parts and labor. The components used to power the vehicle were assembled in the United States, and then incorporated into the vehicle in the United States.</P>
                <P>In the case at hand, various imported components such as the chassis, e-axle, and PDU cannot independently function and operate as an electric vehicle. These components need to be assembled in the United States with other necessary components of U.S. origin, such as the batteries, converter, wheels, and front axle. Furthermore, given the complexity and duration of the U.S. manufacturing process, such as installation, calibration, mounting, and preparation of the product, we consider these operations to be more than mere assembly. Importantly, 67% of the total cost of the truck is comprised of U.S.-made products.</P>
                <P>This case is distinguishable from HQ H302821, dated July 26, 2021, in which we held that the assembly of Volvo vehicles in Sweden as part of a “knockdown operation” did not result in a substantial transformation. Unlike in that case, where the Chinese subassemblies had pre-determined end uses and did not undergo a change in character and use during the assembly process in Sweden, here, applying the name, character and use test, the imported components lose their individual identities and will become an integral part of a new article possessing a new name, character, and use. The assembly of the Tre Bev in the United States constitutes a substantial transformation resulting in an article with a new name, character, and use.</P>
                <P>
                    Based on the foregoing, we find that the last substantial transformation occurs in the United States, and therefore, the Tre Bev battery-electric semi-truck is not a product of a foreign country or instrumentality designated pursuant to 25 U.S.C. 2511(b). As to whether the Tre Bev produced in the United States qualifies as a “U.S.-made end product,” you may wish to consult with the relevant government procuring agency and review 
                    <E T="03">Acetris Health, LLC</E>
                     v. 
                    <E T="03">United States,</E>
                     949 F.3d 719 (Fed. Cir. 2020).
                </P>
                <HD SOURCE="HD3">HOLDING</HD>
                <P>Based on the information outlined above, we determine that the components imported into the United States undergo a substantial transformation when made into Nikola's Tre Bev, class 8, battery-electric semi-truck.</P>
                <P>
                    Notice of this final determination will be given in the 
                    <E T="04">Federal Register</E>
                    <E T="03">,</E>
                     as required by 19 CFR 177.29. Any party-at-interest other than the party which requested this final determination may request, pursuant to 19 CFR 177.31, that CBP reexamine the matter anew and issue a new final determination. Pursuant to 19 CFR 177.30, any party-at-interest may, within 30 days of publication of the 
                    <E T="04">Federal Register</E>
                     Notice referenced above, seek judicial review of this final determination before the U.S. Court of International Trade.
                </P>
                <EXTRACT>
                    <P>Sincerely,</P>
                    <FP>Alice A. Kipel,</FP>
                    <FP>
                        <E T="03">Executive Director, Regulations &amp; Rulings, Office of Trade</E>
                        .
                    </FP>
                </EXTRACT>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10504 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-14-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4719-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Maine; Amendment No. 1 to Notice of a Major Disaster Declaration</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This notice amends the notice of a major disaster declaration for the State of Maine (FEMA-4719-DR), dated July 6, 2023, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This change occurred on March 8, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Robert V. Fogel, of FEMA is appointed to act as the Federal Coordinating Officer for this disaster.</P>
                <P>This action terminates the appointment of William F. Roy as Federal Coordinating Officer for this disaster.</P>
                <EXTRACT>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10444 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <PRTPAGE P="41974"/>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4680-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Florida; Amendment No. 3 to Notice of a Major Disaster Declaration</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This notice amends the notice of a major disaster declaration for the State of Florida (FEMA-4680-DR), dated December 13, 2022, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This change occurred on March 1, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, John E. Brogan, of FEMA is appointed to act as the Federal Coordinating Officer for this disaster.</P>
                <P>This action terminates the appointment of Brett H. Howard as Federal Coordinating Officer for this disaster.</P>
                <EXTRACT>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10440 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4709-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Florida; Amendment No. 1 to Notice of a Major Disaster Declaration</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This notice amends the notice of a major disaster declaration for the State of Florida (FEMA-4709-DR), dated April 27, 2023, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This change occurred on March 1, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, John E. Brogan, of FEMA is appointed to act as the Federal Coordinating Officer for this disaster.</P>
                <P>This action terminates the appointment of Brett H. Howard as Federal Coordinating Officer for this disaster.</P>
                <EXTRACT>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10443 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4697-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Mississippi; Amendment No. 5 to Notice of a Major Disaster Declaration</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This notice amends the notice of a major disaster declaration for the State of Mississippi (FEMA-4697-DR), dated March 26, 2023, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This change occurred on March 12, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Jeremy C. Slinker, of FEMA is appointed to act as the Federal Coordinating Officer for this disaster.</P>
                <P>This action terminates the appointment of Darryl L. Dragoo as Federal Coordinating Officer for this disaster.</P>
                <EXTRACT>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10442 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <PRTPAGE P="41975"/>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4766-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Rhode Island; Major Disaster and Related Determinations</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This is a notice of the Presidential declaration of a major disaster for the State of Rhode Island (FEMA-4766-DR), dated March 20, 2024, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The declaration was issued March 20, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    Notice is hereby given that, in a letter dated March 20, 2024, the President issued a major disaster declaration under the authority of the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                    <E T="03">et seq.</E>
                     (the “Stafford Act”), as follows:
                </P>
                <EXTRACT>
                    <P>
                        I have determined that the damage in certain areas of the State of Rhode Island resulting from severe storms and flooding during the period of January 9 to January 13, 2024, is of sufficient severity and magnitude to warrant a major disaster declaration under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                        <E T="03">et seq.</E>
                         (the “Stafford Act”). Therefore, I declare that such a major disaster exists in the State of Rhode Island.
                    </P>
                    <P>In order to provide Federal assistance, you are hereby authorized to allocate from funds available for these purposes such amounts as you find necessary for Federal disaster assistance and administrative expenses.</P>
                    <P>You are authorized to provide Individual Assistance in the designated areas and Hazard Mitigation throughout the State. Consistent with the requirement that Federal assistance be supplemental, any Federal funds provided under the Stafford Act for Hazard Mitigation and Other Needs Assistance under section 408 will be limited to 75 percent of the total eligible costs.</P>
                    <P>Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.</P>
                </EXTRACT>
                <P>The time period prescribed for the implementation of section 310(a), Priority to Certain Applications for Public Facility and Public Housing Assistance, 42 U.S.C. 5153, shall be for a period not to exceed six months after the date of this declaration.</P>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Robert V. Fogel, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.</P>
                <P>The following areas of the State of Rhode Island have been designated as adversely affected by this major disaster:</P>
                <EXTRACT>
                    <P>Kent, Providence, and Washington Counties for Individual Assistance.</P>
                    <P>All areas within the State of Rhode Island are eligible for assistance under the Hazard Mitigation Grant Program.</P>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10457 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4769-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>California; Major Disaster and Related Determinations</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This is a notice of the Presidential declaration of a major disaster for the State of California (FEMA-4769-DR), dated April 13, 2024, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The declaration was issued April 13, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    Notice is hereby given that, in a letter dated April 13, 2024, the President issued a major disaster declaration under the authority of the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                    <E T="03">et seq.</E>
                     (the “Stafford Act”), as follows:
                </P>
                <EXTRACT>
                    <P>
                        I have determined that the damage in certain areas of the State of California resulting from severe winter storms, tornadoes, flooding, landslides, and mudslides during the period of January 31 to February 9, 2024, is of sufficient severity and magnitude to warrant a major disaster declaration under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                        <E T="03">et seq.</E>
                         (the “Stafford Act”). Therefore, I declare that such a major disaster exists in the State of California.
                    </P>
                    <P>In order to provide Federal assistance, you are hereby authorized to allocate from funds available for these purposes such amounts as you find necessary for Federal disaster assistance and administrative expenses.</P>
                    <P>You are authorized to provide Public Assistance in the designated areas and Hazard Mitigation throughout the State. Consistent with the requirement that Federal assistance be supplemental, any Federal funds provided under the Stafford Act for Public Assistance and Hazard Mitigation will be limited to 75 percent of the total eligible costs.</P>
                    <P>Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.</P>
                </EXTRACT>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Andrew F. Grant, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.</P>
                <P>The following areas of the State of California have been designated as adversely affected by this major disaster:</P>
                <EXTRACT>
                    <P>Butte, Glenn, Los Angeles, Monterey, San Luis Obispo, Santa Barbara, Santa Cruz, Sutter, and Ventura Counties for Public Assistance.</P>
                    <P>All areas within the State of California are eligible for assistance under the Hazard Mitigation Grant Program.</P>
                    <P>
                        The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, 
                        <PRTPAGE P="41976"/>
                        Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.
                    </P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10460 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4767-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Alaska; Major Disaster and Related Determinations</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This is a notice of the Presidential declaration of a major disaster for the State of Alaska (FEMA-4767-DR), dated April 6, 2024, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The declaration was issued April 6, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    Notice is hereby given that, in a letter dated April 6, 2024, the President issued a major disaster declaration under the authority of the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                    <E T="03">et seq.</E>
                     (the “Stafford Act”), as follows:
                </P>
                <EXTRACT>
                    <P>
                        I have determined that the damage in certain areas of the State of Alaska resulting from a severe storm, flooding, and landslides on November 20, 2023, is of sufficient severity and magnitude to warrant a major disaster declaration under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                        <E T="03">et seq.</E>
                         (the “Stafford Act”). Therefore, I declare that such a major disaster exists in the State of Alaska.
                    </P>
                    <P>In order to provide Federal assistance, you are hereby authorized to allocate from funds available for these purposes such amounts as you find necessary for Federal disaster assistance and administrative expenses.</P>
                    <P>You are authorized to provide Public Assistance in the designated areas and Hazard Mitigation throughout the State. Consistent with the requirement that Federal assistance be supplemental, any Federal funds provided under the Stafford Act for Public Assistance and Hazard Mitigation will be limited to 75 percent of the total eligible costs.</P>
                    <P>Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.</P>
                </EXTRACT>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Brian F. Schiller, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.</P>
                <P>The following areas of the State of Alaska have been designated as adversely affected by this major disaster:</P>
                <EXTRACT>
                    <P>Prince of Wales-Hyder Census Area, Southeast Island Regional Educational Attendance Area, and the City and Borough of Wrangell for Public Assistance.</P>
                    <P>All areas within the State of Alaska are eligible for assistance under the Hazard Mitigation Grant Program.</P>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10458 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4764-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Maine; Major Disaster and Related Determinations</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This is a notice of the Presidential declaration of a major disaster for the State of Maine (FEMA-4764-DR), dated March 20, 2024, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The declaration was issued March 20, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    Notice is hereby given that, in a letter dated March 20, 2024, the President issued a major disaster declaration under the authority of the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                    <E T="03">et seq.</E>
                     (the “Stafford Act”), as follows:
                </P>
                <EXTRACT>
                    <P>
                        I have determined that the damage in certain areas of the State of Maine resulting from severe storms and flooding during the period of January 9 to January 13, 2024, is of sufficient severity and magnitude to warrant a major disaster declaration under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                        <E T="03">et seq.</E>
                         (the “Stafford Act”). Therefore, I declare that such a major disaster exists in the State of Maine.
                    </P>
                    <P>In order to provide Federal assistance, you are hereby authorized to allocate from funds available for these purposes such amounts as you find necessary for Federal disaster assistance and administrative expenses.</P>
                    <P>You are authorized to provide Individual Assistance and Public Assistance in the designated areas and Hazard Mitigation throughout the State.</P>
                    <P>Consistent with the requirement that Federal assistance be supplemental, any Federal funds provided under the Stafford Act for Public Assistance, Hazard Mitigation, and Other Needs Assistance under section 408 will be limited to 75 percent of the total eligible costs.</P>
                    <P>Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.</P>
                </EXTRACT>
                <P>The time period prescribed for the implementation of section 310(a), Priority to Certain Applications for Public Facility and Public Housing Assistance, 42 U.S.C. 5153, shall be for a period not to exceed six months after the date of this declaration.</P>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Robert V. Fogel, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.</P>
                <P>The following areas of the State of Maine have been designated as adversely affected by this major disaster:</P>
                <EXTRACT>
                    <P>Cumberland, Hancock, Knox, Lincoln, Sagadahoc, Waldo, Washington, and York Counties for Individual Assistance.</P>
                    <P>Cumberland, Hancock, Knox, Lincoln, Sagadahoc, Waldo, Washington, and York Counties for Public Assistance.</P>
                    <P>All areas within the State of Maine are eligible for assistance under the Hazard Mitigation Grant Program.</P>
                    <P>
                        The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, 
                        <PRTPAGE P="41977"/>
                        Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.
                    </P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10455 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4736-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Maine; Amendment No. 1 to Notice of a Major Disaster Declaration</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This notice amends the notice of a major disaster declaration for the State of Maine (FEMA-4736-DR), dated September 5, 2023, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This change occurred on March 8, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Robert V. Fogel, of FEMA is appointed to act as the Federal Coordinating Officer for this disaster.</P>
                <P>This action terminates the appointment of William F. Roy as Federal Coordinating Officer for this disaster.</P>
                <EXTRACT>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10447 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4673-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Florida; Amendment No. 16 to Notice of a Major Disaster Declaration</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This notice amends the notice of a major disaster declaration for the State of Florida (FEMA-4673-DR), dated September 29, 2022, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This change occurred on March 1, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, John E. Brogan, of FEMA is appointed to act as the Federal Coordinating Officer for this disaster.</P>
                <P>This action terminates the appointment of Brett H. Howard as Federal Coordinating Officer for this disaster.</P>
                <EXTRACT>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10439 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4765-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Rhode Island; Major Disaster and Related Determinations</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This is a notice of the Presidential declaration of a major disaster for the State of Rhode Island (FEMA-4765-DR), dated March 20, 2024, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The declaration was issued March 20, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    Notice is hereby given that, in a letter dated March 20, 2024, the President issued a major disaster declaration under the authority of the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                    <E T="03">et seq.</E>
                     (the “Stafford Act”), as follows:
                </P>
                <EXTRACT>
                    <P>
                        I have determined that the damage in certain areas of the State of Rhode Island resulting from a severe storm and flooding during the period of December 17 to December 19, 2023, is of sufficient severity and magnitude to warrant a major disaster declaration under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                        <E T="03">et seq.</E>
                         (the “Stafford Act”). Therefore, I declare that such a major disaster exists in the State of Rhode Island.
                    </P>
                    <P>In order to provide Federal assistance, you are hereby authorized to allocate from funds available for these purposes such amounts as you find necessary for Federal disaster assistance and administrative expenses.</P>
                    <P>
                        You are authorized to provide Individual Assistance in the designated areas and Hazard Mitigation throughout the State. Consistent with the requirement that Federal assistance be supplemental, any Federal funds provided under the Stafford Act for 
                        <PRTPAGE P="41978"/>
                        Hazard Mitigation and Other Needs Assistance under section 408 will be limited to 75 percent of the total eligible costs.
                    </P>
                    <P>Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.</P>
                </EXTRACT>
                <P>The time period prescribed for the implementation of section 310(a), Priority to Certain Applications for Public Facility and Public Housing Assistance, 42 U.S.C. 5153, shall be for a period not to exceed six months after the date of this declaration.</P>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Robert V. Fogel, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.</P>
                <P>The following areas of the State of Rhode Island have been designated as adversely affected by this major disaster:</P>
                <EXTRACT>
                    <P>Kent, Providence, and Washington Counties for Individual Assistance.</P>
                    <P>All areas within the State of Rhode Island are eligible for assistance under the Hazard Mitigation Grant Program.</P>
                    <FP>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</FP>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10456 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4762-DR] [Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Vermont; Major Disaster and Related Determinations</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This is a notice of the Presidential declaration of a major disaster for the State of Vermont (FEMA-4762-DR), dated March 2, 2024, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The declaration was issued March 2, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    Notice is hereby given that, in a letter dated March 2, 2024, the President issued a major disaster declaration under the authority of the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                    <E T="03">et seq.</E>
                     (the “Stafford Act”), as follows:
                </P>
                <EXTRACT>
                    <P>
                        I have determined that the damage in certain areas of the State of Vermont resulting from a severe storm and flooding during the period of December 18 to December 19, 2023, is of sufficient severity and magnitude to warrant a major disaster declaration under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                        <E T="03">et seq.</E>
                         (the “Stafford Act”). Therefore, I declare that such a major disaster exists in the State of Vermont.
                    </P>
                    <P>In order to provide Federal assistance, you are hereby authorized to allocate from funds available for these purposes such amounts as you find necessary for Federal disaster assistance and administrative expenses.</P>
                    <P>You are authorized to provide Public Assistance in the designated areas and Hazard Mitigation throughout the State. Consistent with the requirement that Federal assistance be supplemental, any Federal funds provided under the Stafford Act for Public Assistance and Hazard Mitigation will be limited to 75 percent of the total eligible costs.</P>
                    <P>Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.</P>
                </EXTRACT>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, William F. Roy, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.</P>
                <P>The following areas of the State of Vermont have been designated as adversely affected by this major disaster:</P>
                <EXTRACT>
                    <P>Essex, Lamoille, Orange, Orleans, Rutland, Windham, and Windsor Counties for Public Assistance.</P>
                    <P>All areas within the State of Vermont are eligible for assistance under the Hazard Mitigation Grant Program.</P>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10453 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4727-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Mississippi; Amendment No. 3 to Notice of a Major Disaster Declaration</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This notice amends the notice of a major disaster declaration for the State of Mississippi (FEMA-4727-DR), dated August 12, 2023, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This change occurred on March 12, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Jeremy C. Slinker, of FEMA is appointed to act as the Federal Coordinating Officer for this disaster.</P>
                <P>This action terminates the appointment of Darryl L. Dragoo as Federal Coordinating Officer for this disaster.</P>
                <EXTRACT>
                    <P>
                        The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to 
                        <PRTPAGE P="41979"/>
                        Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.
                    </P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10445 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4734-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Florida; Amendment No. 8 to Notice of a Major Disaster Declaration</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This notice amends the notice of a major disaster declaration for the State of Florida (FEMA-4709-DR), dated August 31, 2023, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This change occurred on March 1, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, John E. Brogan, of FEMA is appointed to act as the Federal Coordinating Officer for this disaster.</P>
                <P>This action terminates the appointment of Brett H. Howard as Federal Coordinating Officer for this disaster.</P>
                <EXTRACT>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10446 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4759-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Washington; Amendment No. 2 to Notice of a Major Disaster Declaration</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This notice amends the notice of a major disaster declaration for the State of Washington (FEMA-4759-DR), dated February 15, 2024, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This amendment was issued April 3, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The notice of a major disaster declaration for the State of Washington is hereby amended to include the following areas among those areas determined to have been adversely affected by the event declared a major disaster by the President in his declaration of February 15, 2024.</P>
                <EXTRACT>
                    <P>Spokane County for permanent work [Categories C-G] (already designated for debris removal and emergency protective measures [Categories A and B], including direct federal assistance, under the Public Assistance program).</P>
                    <P>Whitman County for Public Assistance.</P>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050 Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10451 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4737-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Maine; Amendment No. 1 to Notice of a Major Disaster Declaration</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This notice amends the notice of a major disaster declaration for the State of Maine (FEMA-4737-DR), dated September 6, 2023, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This change occurred on March 8, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Robert V. Fogel, of FEMA is appointed to act as the Federal Coordinating Officer for this disaster.</P>
                <P>This action terminates the appointment of William F. Roy as Federal Coordinating Officer for this disaster.</P>
                <EXTRACT>
                    <P>
                        The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance 
                        <PRTPAGE P="41980"/>
                        (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.
                    </P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10448 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-3600-EM; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Louisiana; Amendment No. 3 to Notice of an Emergency Declaration</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This notice amends the notice of an emergency declaration for the State of Louisiana (FEMA-3600-DR), dated September 27, 2023, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This amendment was issued April 19, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>Notice is hereby given that the incident period for this emergency is closed effective February 9, 2024.</P>
                <EXTRACT>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10438 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4768-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Oregon; Major Disaster and Related Determinations</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This is a notice of the Presidential declaration of a major disaster for the State of Oregon (FEMA-4768-DR), dated April 13, 2024, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The declaration was issued April 13, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    Notice is hereby given that, in a letter dated April 13, 2024, the President issued a major disaster declaration under the authority of the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                    <E T="03">et seq.</E>
                     (the “Stafford Act”), as follows:
                </P>
                <EXTRACT>
                    <P>
                        I have determined that the damage in certain areas of the State of Oregon resulting from severe winter storms, straight-line winds, landslides, and mudslides during the period of January 10 to January 22, 2024, is of sufficient severity and magnitude to warrant a major disaster declaration under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                        <E T="03">et seq.</E>
                         (the “Stafford Act”). Therefore, I declare that such a major disaster exists in the State of Oregon.
                    </P>
                    <P>In order to provide Federal assistance, you are hereby authorized to allocate from funds available for these purposes such amounts as you find necessary for Federal disaster assistance and administrative expenses.</P>
                    <P>You are authorized to provide Public Assistance in the designated areas and Hazard Mitigation throughout the State. Consistent with the requirement that Federal assistance be supplemental, any Federal funds provided under the Stafford Act for Public Assistance and Hazard Mitigation will be limited to 75 percent of the total eligible costs.</P>
                    <P>Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.</P>
                </EXTRACT>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Yolanda J. Jackson, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.</P>
                <P>The following areas of the State of Oregon have been designated as adversely affected by this major disaster:</P>
                <EXTRACT>
                    <P>Benton, Clackamas, Coos, Hood River, Lane, Lincoln, Linn, Multnomah, Sherman, Tillamook, and Wasco Counties and the Confederated Tribes of Siletz Indians for Public Assistance.</P>
                    <P>All areas within the State of Oregon are eligible for assistance under the Hazard Mitigation Grant Program.</P>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10459 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4763-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Wrangell Cooperative Association; Major Disaster and Related Determinations</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This is a notice of the Presidential declaration of a major disaster for the Wrangell Cooperative Association (FEMA-4763-DR), dated March 15, 2024, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The declaration was issued March 15, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    Notice is hereby given that, in a letter dated March 15, 2024, the President issued a major disaster declaration under the 
                    <PRTPAGE P="41981"/>
                    authority of the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                    <E T="03">et seq.</E>
                     (the “Stafford Act”), as follows:
                </P>
                <EXTRACT>
                    <P>
                        I have determined that the damage to the lands associated with the Wrangell Cooperative Association resulting from a severe storm, landslides, and mudslides on November 20, 2023, is of sufficient severity and magnitude to warrant a major disaster declaration under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                        <E T="03">et seq.</E>
                         (the “Stafford Act”). Therefore, I declare that such a major disaster exists for the Wrangell Cooperative Association.
                    </P>
                    <P>In order to provide Federal assistance, you are hereby authorized to allocate from funds available for these purposes such amounts as you find necessary for Federal disaster assistance and administrative expenses.</P>
                    <P>You are authorized to provide Individual Assistance, emergency protective measures under the Public Assistance program, and Hazard Mitigation for the Wrangell Cooperative Association. Consistent with the requirement that Federal assistance be supplemental, any Federal funds provided under the Stafford Act for Public Assistance, Hazard Mitigation, and Other Needs Assistance under section 408 will be limited to 75 percent of the total eligible costs.</P>
                    <P>Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.</P>
                </EXTRACT>
                <P>The time period prescribed for the implementation of section 310(a), Priority to Certain Applications for Public Facility and Public Housing Assistance, 42 U.S.C. 5153, shall be for a period not to exceed six months after the date of this declaration.</P>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Brian F. Schiller, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.</P>
                <P>The following areas have been designated as adversely affected by this major disaster:</P>
                <EXTRACT>
                    <P>Wrangell Cooperative Association for Individual Assistance.</P>
                    <P>Emergency protective measures under the Public Assistance program for the Wrangell Cooperative Association.</P>
                    <P>The Wrangell Cooperative Association is eligible to apply for assistance under the Hazard Mitigation Grant Program.</P>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10454 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4696-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Maine; Amendment No. 1 to Notice of a Major Disaster Declaration</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This notice amends the notice of a major disaster declaration for the State of Maine (FEMA-4696-DR), dated March 22, 2023, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This change occurred on March 8, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Robert V. Fogel, of FEMA is appointed to act as the Federal Coordinating Officer for this disaster.</P>
                <P>This action terminates the appointment of William F. Roy as Federal Coordinating Officer for this disaster.</P>
                <EXTRACT>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10441 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4761-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>New Hampshire; Major Disaster and Related Determinations</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This is a notice of the Presidential declaration of a major disaster for the State of New Hampshire (FEMA-4761-DR), dated February 27, 2024, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The declaration was issued February 27, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    Notice is hereby given that, in a letter dated February 27, 2024, the President issued a major disaster declaration under the authority of the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                    <E T="03">et seq.</E>
                     (the “Stafford Act”), as follows:
                </P>
                <EXTRACT>
                    <P>
                        I have determined that the damage in certain areas of the State of New Hampshire resulting from a severe storm and flooding during the period of December 17 to December 21, 2023, is of sufficient severity and magnitude to warrant a major disaster declaration under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 
                        <E T="03">et seq.</E>
                         (the “Stafford Act”). Therefore, I declare that such a major disaster exists in the State of New Hampshire.
                    </P>
                    <P>In order to provide Federal assistance, you are hereby authorized to allocate from funds available for these purposes such amounts as you find necessary for Federal disaster assistance and administrative expenses.</P>
                    <P>
                        You are authorized to provide Public Assistance in the designated areas and Hazard Mitigation throughout the State. Consistent with the requirement that Federal assistance be supplemental, any Federal funds provided under the Stafford Act for Public Assistance and Hazard Mitigation will 
                        <PRTPAGE P="41982"/>
                        be limited to 75 percent of the total eligible costs.
                    </P>
                    <P>Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.</P>
                </EXTRACT>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, William F. Roy, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.</P>
                <P>The following areas of the State of New Hampshire have been designated as adversely affected by this major disaster:</P>
                <EXTRACT>
                    <P>Carroll, Coos, and Grafton Counties for Public Assistance.</P>
                    <P>All areas within the State of New Hampshire are eligible for assistance under the Hazard Mitigation Grant Program.</P>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10452 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4752-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Utah; Amendment No. 1 to Notice of a Major Disaster Declaration</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This notice amends the notice of a major disaster declaration for the State of Utah (FEMA-4752-DR), dated December 23, 2023, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This change occurred on April 1, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Edwin J. Martin, of FEMA is appointed to act as the Federal Coordinating Officer for this disaster.</P>
                <P>This action terminates the appointment of Jon K. Huss as Federal Coordinating Officer for this disaster.</P>
                <EXTRACT>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10449 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF HOMELAND SECURITY</AGENCY>
                <SUBAGY>Federal Emergency Management Agency</SUBAGY>
                <DEPDOC>[Internal Agency Docket No. FEMA-4754-DR; Docket ID FEMA-2024-0001]</DEPDOC>
                <SUBJECT>Maine; Amendment No. 2 to Notice of a Major Disaster Declaration</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Emergency Management Agency, DHS.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This notice amends the notice of a major disaster declaration for the State of Maine (FEMA-4754-DR), dated January 30, 2024, and related determinations.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This change occurred on March 8, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW, Washington, DC 20472, (202) 646-2833.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Robert V. Fogel, of FEMA is appointed to act as the Federal Coordinating Officer for this disaster.</P>
                <P>This action terminates the appointment of William F. Roy as Federal Coordinating Officer for this disaster.</P>
                <EXTRACT>
                    <P>The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.</P>
                </EXTRACT>
                <SIG>
                    <NAME>Deanne Criswell,</NAME>
                    <TITLE>Administrator, Federal Emergency Management Agency.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10450 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 9111-23-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF THE INTERIOR</AGENCY>
                <SUBAGY>Geological Survey</SUBAGY>
                <DEPDOC>[GX23ZQ00F080400, OMB Control Number 1028-0048]</DEPDOC>
                <SUBJECT>Agency Information Collection Activities: Did You Feel It? Earthquake Questionnaire</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>U.S. Geological Survey, Department of the Interior.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of renewed information collection; request for comment.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>In accordance with the Paperwork Reduction Act (PRA) of 1995, the U.S. Geological Survey (USGS) is requesting to renew an information collection with revisions.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Interested persons are invited to submit comments on or before June 13, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Written comments and recommendations for the proposed information collection should be sent within 30 days of publication of this notice to 
                        <E T="03">www.reginfo.gov/public/do/PRAMain.</E>
                         Find this particular information collection by selecting “Currently under Review—Open for 
                        <PRTPAGE P="41983"/>
                        Public Comments” or by using the search function. Please provide a copy of your comments by mail to USGS, Information Collections Clearance Officer, 12201 Sunrise Valley Drive, MS 159, Reston, VA 20192 or by email to 
                        <E T="03">gs-info_collections@usgs.gov.</E>
                         Please reference OMB Control Number 1028-0048.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        To request additional information about this information collection request (ICR), contact Sara McBride by email at 
                        <E T="03">skmcbride@usgs.gov</E>
                         or by telephone at 650-750-5270. Individuals in the United States who are deaf, deafblind, hard of hearing, or have a speech disability may dial 711 (TTY, TDD, or TeleBraille) to access telecommunications relay services. Individuals outside the United States should use the relay services offered within their country to make international calls to the point-of-contact in the United States. You may also view the ICR at 
                        <E T="03">http://www.reginfo.gov/public/do/PRAMain.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    In accordance with PRA of 1995 (44 U.S.C. 3501 
                    <E T="03">et seq.</E>
                    ) and 5 CFR 1320.8(d)(1), we provide the general public and other federal agencies with an opportunity to comment on new, proposed, revised, and continuing collections of information. This helps us assess the impact of our information collection requirements and minimize the public's reporting burden. It also helps the public understand our information collection requirements and provide the requested data in the desired format.
                </P>
                <P>
                    A 
                    <E T="04">Federal Register</E>
                     notice with a 60-day public comment period soliciting comments on this collection of information was published on November 17, 2022. (87 FR 69039). No comments were received.
                </P>
                <P>As part of our continuing effort to reduce paperwork and respondent burdens, we are again soliciting comments from the public and other federal agencies on the proposed ICR that is described below. We are especially interested in public comment addressing the following:</P>
                <P>(1) Whether or not the collection of information is necessary for the proper performance of the functions of the agency, including whether or not the information will have practical utility;</P>
                <P>(2) The accuracy of our estimate of the burden for this collection of information, including the validity of the methodology and assumptions used;</P>
                <P>(3) Ways to enhance the quality, utility, and clarity of the information to be collected; and</P>
                <P>
                    (4) How the agency might minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, 
                    <E T="03">e.g.,</E>
                     permitting electronic submission of response.
                </P>
                <P>Comments that you submit in response to this notice are a matter of public record. Before including your address, phone number, email address, or other personally identifiable information (PII) in your comment, you should be aware that your entire comment—including your PII—may be made publicly available at any time. While you can ask us in your comment to withhold your PII from public review, we cannot guarantee that we will be able to do so.</P>
                <P>
                    <E T="03">Abstract:</E>
                     The information gathered in the questionnaire is used by the USGS to provide overviews of the effects of earthquakes on humans and on the human environment. Summaries of the effects of earthquakes, and isoseismal maps that represent them, are published in Preliminary Determination of Epicenters publications of the USGS, in Open-File Reports, or in research publications. Summaries and maps are also distributed electronically from USGS earthquake information web pages. In 1998, we began experimenting with an electronic version of the questionnaire as a way of collecting information from people who were looking at the USGS earthquake information website. The experiment was so successful and the number of questionnaire responses for significant earthquakes increased so quickly, that we were able to eliminate other collection methods. We have collected data exclusively with the web-based questionnaire since 2002.
                </P>
                <P>This addition of the questions means that people who received an alert via the ShakeAlert System or any earthquake early warning system can report their experiences to us quickly, in combination with their experiences of the earthquake. This combined data set can tell us much about how the ShakeAlert system operates, when people receive alerts, how they receive them and what they did once they received them. This is critical information for us to improve the ShakeAlert System.</P>
                <P>
                    <E T="03">Title of Collection:</E>
                     Did You Feel It? Earthquake Questionnaire.
                </P>
                <P>
                    <E T="03">OMB Control Number:</E>
                     1028-0048.
                </P>
                <P>
                    <E T="03">Form Number:</E>
                     None.
                </P>
                <P>
                    <E T="03">Type of Review:</E>
                     Renewal with revisions.
                </P>
                <P>
                    <E T="03">Respondents/Affected Public:</E>
                     Individuals/households.
                </P>
                <P>
                    <E T="03">Total Estimated Number of Annual Respondents:</E>
                     300,000.
                </P>
                <P>
                    <E T="03">Total Estimated Number of Annual Responses:</E>
                     300,000.
                </P>
                <P>
                    <E T="03">Estimated Completion Time per Response:</E>
                     4 minutes.
                </P>
                <P>
                    <E T="03">Total Estimated Number of Annual Burden Hours:</E>
                     20,000.
                </P>
                <P>
                    <E T="03">Respondent's Obligation:</E>
                     Voluntary.
                </P>
                <P>
                    <E T="03">Frequency of Collection:</E>
                     One-time, in an online survey.
                </P>
                <P>
                    <E T="03">Total Estimated Annual Nonhour Burden Cost:</E>
                     0.
                </P>
                <P>An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.</P>
                <P>The authority for this action is the PRA.</P>
                <SIG>
                    <NAME>Gary D. Latzke,</NAME>
                    <TITLE>Chief of Staff, USGS, Natural Hazards Mission Area.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10362 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4338-11-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF THE INTERIOR</AGENCY>
                <SUBAGY>Bureau of Indian Affairs</SUBAGY>
                <DEPDOC>[245A2100DD/AAMM001010/A0A600000.999900]</DEPDOC>
                <SUBJECT>Santa Ana Pueblo Liquor Code Amendment</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Bureau of Indian Affairs, Interior.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>
                        This notice publishes the Pueblo of Santa Ana Liquor Ordinance. This Ordinance amends the existing Liquor Ordinance, published in the 
                        <E T="04">Federal Register</E>
                         on September 9, 2015.
                    </P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This code shall become effective May 14, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Mr. Eric Rodriguez, Tribal Government, Southwest Regional Office, Bureau of Indian Affairs, 1001 Indian School Road NW, Albuquerque, NM 87104-2303, Phone: (505) 536-3100; Fax: (505) 563-3101.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    Pursuant to the Act of August 15, 1953, Public Law 83-277, 67 Stat. 586, 18 U.S.C. 1161, as interpreted by the Supreme Court in 
                    <E T="03">Rice</E>
                     v. 
                    <E T="03">Rehner,</E>
                     463 U.S. 713 (1983), the Secretary of the Interior shall certify and publish in the 
                    <E T="04">Federal Register</E>
                     notice of adopted liquor ordinances for the purpose of regulating liquor transactions in Indian country.
                </P>
                <P>
                    This notice is published in accordance with the authority delegated 
                    <PRTPAGE P="41984"/>
                    by the Secretary of the Interior to the Assistant Secretary-Indian Affairs. I certify that the Pueblo of Santa Ana Council of the Pueblo of Santa Ana duly adopted this amendment to the Pueblo's title XVII, article 3, Liquor Code by Resolution No. 2024-R-03 on March 7, 2024.
                </P>
                <SIG>
                    <NAME>Bryan Newland,</NAME>
                    <TITLE>Assistant Secretary—Indian Affairs.</TITLE>
                </SIG>
                <HD SOURCE="HD1">Pueblo of Santa ANA Tribal Code</HD>
                <HD SOURCE="HD1">Title 17: Regulation of Business And Commerce</HD>
                <HD SOURCE="HD1">Article 3—Liquor Code</HD>
                <HD SOURCE="HD1">Sec. 17-3-1: Findings</HD>
                <P>The Tribal Council finds as follows:</P>
                <P>A. The introduction, possession and sale of alcoholic beverages on the Santa Ana Indian Reservation has, for a long time, been clearly recognized as a matter of special concern to the Pueblo and its members and to the United States; and</P>
                <P>B. Under federal law and New Mexico state law, and as a matter of inherent Tribal sovereignty, the question of when and to what extent alcoholic beverages may be introduced into and sold or consumed within the Santa Ana Indian Reservation is to be decided by the governing body of the Tribe; and</P>
                <P>C. It is desirable that the Tribal Council legislate comprehensively on the subject of the sale and possession of alcoholic beverages within the Santa Ana Indian Reservation both to establish a consistent and reasonable Tribal policy on this important subject, as well as to facilitate economic development projects within the Santa Ana Indian Reservation that may involve outlets for the sale and consumption of alcoholic beverages; and</P>
                <P>D. It is the policy of the Tribal Council that the introduction, sale and consumption of alcoholic beverages within the Santa Ana Indian Reservation be carefully regulated so as to protect the public health, safety and welfare, and that licensees be made fully accountable for violations of conditions of their licenses and the consequences thereof.</P>
                <HD SOURCE="HD1">Sec. 17-3-2: Definitions</HD>
                <P>As used in this Article, the following words shall have the following meanings:</P>
                <P>A. “Council” means the Tribal Council of the Pueblo of Santa Ana.</P>
                <P>B. “Development Area” means those lands within the Santa Ana Indian Reservation and that are situated west of the Rio Grande and south of the Rio Jemez, but not including any lands within the boundaries of the Santa Ana Pueblo Grant as confirmed by Congress by the Act of February 9, 1869, c. 26, 15 Stat. 438 (provided however, that if such term is more specifically defined in a planning or zoning statute or ordinance adopted by the Tribal Council, or in any regulations issued under the authority of any such duly adopted planning or zoning statute or ordinance, such definition shall supersede and control the definition of such term set forth herein).</P>
                <P>C. “Governor” mans the Governor of the Pueblo of Santa Ana.</P>
                <P>D. “Licensed Premises” means the location within the Santa Ana Indian Reservation at which a licensee is permitted to sell and allow the consumption of alcoholic beverages, and may, if requested by the applicant and adopted by the Governor, include any related or associated facilities under the control of the licensee, or within which the licensee is otherwise authorized to conduct business (but subject to any conditions or limitations as to sales within such area that may be imposed by the Governor in issuance of the license).</P>
                <P>E. “Licensee” means a person or entity that has been issued a license to sell alcoholic beverages on the licensed premises under the provisions of this Liquor Code.</P>
                <P>F. “Liquor” or “Alcoholic Beverage” includes the four varieties of liquor commonly referred to as alcohol, spirits, wine and beer, and all fermented, spirituous, vinous or malt liquors or combinations thereof, mixed liquor, any part of which is fermented, spirituous, vinous, or malt liquor, or any otherwise intoxicating liquid, including every liquid or solid or semi-solid or other substance, patented or not, containing alcohol, spirits, wine or beer and intended for oral consumption.</P>
                <P>G. “Liquor Code” means the Santa Ana Pueblo Liquor Code, this Article.</P>
                <P>H. “Person” means any natural person, partnership, corporation, joint venture, association, or other legal entity.</P>
                <P>I. “Pueblo” or “Tribe” means the Pueblo of Santa Ana.</P>
                <P>J. “Sale” or “sell” means any exchange, barter, or other transfer of goods from one person to another for commercial purposes, whether with or without consideration.</P>
                <P>K. “Santa Ana Indian Reservation” means all lands within the exterior boundaries of the Santa Ana Indian Reservation, all lands within the exterior boundaries of the El Ranchito Grant and the Santa Ana Pueblo Grant, and all other lands owned by the Pueblo subject to federal law restrictions on alienation or held by the United States for the use and benefit of the Pueblo.</P>
                <P>L. “Special Event” means a bona fide special occasion such as a fair, fiesta, show, tournament, contest, meeting, picnic or similar event within the Development Area, sponsored by an established business or organization, lasting no more than three days. A special event may be open to the public or to a designated group, and it may be a one-time event or periodic, provided, however, that such events held more than four times a year by the same business or organization may not be deemed special events for purposes of this Liquor Code, in the discretion of the Governor.</P>
                <P>M. “Server” means an individual who sells, serves or dispenses alcoholic beverages for consumption on or off licensed premises, including persons who manage, direct or control the sale or service of alcohol.</P>
                <HD SOURCE="HD1">Sec. 17-3-3: Sovereign Immunity Preserved</HD>
                <P>Nothing in the Liquor Code shall be construed as a waiver or limitation of the sovereign immunity of the Pueblo.</P>
                <HD SOURCE="HD1">Sec. 17-3-4: Initial Compliance</HD>
                <P>
                    No person shall be disqualified from being issued a license under the provisions of this Liquor Code, or shall be found to have violated any provision of this Article, solely because such person, having been duly authorized to engage in the sale of alcoholic beverages within the Santa Ana Indian Reservation under the law as it existed prior to enactment of this Liquor Code, continues to engage in such business without a license issued under the provisions of this Liquor Code after the effective date hereof, so long as such person, within 90 days after such effective date (or within 30 days after receiving written notice from the Pueblo of the enactment of the Liquor Code, whichever is later) submits an application for such license in compliance with the provisions of this Liquor Code, and a license is thereafter issued in due course; provided, however, that upon the issuance of a license under the provisions of this Liquor Code to any person or entity, or upon the rejection of an application for such license by any person or entity, no license issued by the State of New Mexico or issued under the provisions of any prior law of the Pueblo that is held by such person or entity, or that purports to authorize the possession, sale or consumption of alcoholic beverages on premises covered by a license issued (or a license application rejected) under the provisions of this Liquor Code, shall have any further 
                    <PRTPAGE P="41985"/>
                    validity or effect within the Santa Ana Indian Reservation.
                </P>
                <HD SOURCE="HD1">Sec. 17-3-5: Severability</HD>
                <P>In the event any provision of this Liquor Code is held invalid or unenforceable by any court of competent jurisdiction, the remainder of the Code shall continue in full force and effect, notwithstanding the invalidity or unenforceability of such provision, to the fullest extent practicable.</P>
                <HD SOURCE="HD1">Sec. 17-3-6: Prohibition</HD>
                <P>The sale, introduction for sale, purchase, or other dealing in alcoholic beverages, except as is specifically authorized by the Liquor Code, is prohibited within the Santa Ana Indian Reservation.</P>
                <HD SOURCE="HD1">Sec. 17-3-7: Possession for Personal Use</HD>
                <P>A. Except as provided in subsection B of this section, possession of alcoholic beverages for personal use shall be lawful within the Santa Ana Indian Reservation only if such alcoholic beverages were lawfully purchased, whether on or off the Santa Ana Indian Reservation, from a licensed establishment that obtains alcoholic beverages from a New Mexico licensed wholesaler and are possessed by a person or persons 21 years of age or older. Possession of alcoholic beverages is otherwise prohibited.</P>
                <P>B. It shall be unlawful for any person to possess, including in a residence or vehicle, alcoholic beverages within the outer limits of the village of Tamaya (the Pueblo's traditional village on the north side of the Rio Jemez, at the center of the Santa Ana Pueblo Grant) during feast or any traditional gathering or traditional obligation as declared by the War Chief, Lt. War Chief, the Governor, or Lt. Governor.</P>
                <HD SOURCE="HD1">Sec. 17-3-8: Transportation Through Reservation Not Affected</HD>
                <P>Nothing herein shall pertain to the otherwise lawful transportation of alcoholic beverages through the Santa Ana Indian Reservation by persons remaining upon public highways (or other areas paved for motor vehicles) and where such beverages are not delivered, sold at retail or offered for sale at retail to anyone within the Santa Ana Indian Reservation.</P>
                <HD SOURCE="HD1">Sec. 17-3-9: Requirement of Pueblo License</HD>
                <P>No person shall sell any alcoholic beverage within the Santa Ana Indian Reservation at retail, or offer any such beverage for sale at retail, unless such person holds a license issued by the Pueblo under the provisions of this Article.</P>
                <HD SOURCE="HD1">Sec. 17-3-10: All Sales for Personal Use</HD>
                <P>No person licensed to sell alcoholic beverages within the Santa Ana Indian Reservation shall sell any such beverage for resale, but all such sales shall be for the personal use of the purchaser. Nothing herein shall prohibit a duly licensed wholesale dealer in alcoholic beverages from selling and delivering such beverages to properly licensed retailers within the Santa Ana Indian Reservation, so long as such sales and deliveries are otherwise in conformity with the laws of the State of New Mexico and this Liquor Code.</P>
                <HD SOURCE="HD1">Sec. 17-3-11: Package Sales and Sales of Liquor by the Drink Permitted</HD>
                <P>Sales of alcoholic beverages on the Santa Ana Indian Reservation may be in package form or for consumption on the premises, or both, so long as the seller is properly licensed by the Pueblo to make sales of that type. No seller of alcoholic beverages shall permit any person to bring onto premises where liquor by the drink is authorized to be sold any alcoholic beverages purchased elsewhere, unless such person is otherwise licensed to possess or distribute such beverages on such premises, except that a restaurant holding a premises license may allow a customer who is ordering a meal, and who is legally entitled to consume alcoholic beverages, to bring onto the premises one or more bottles of wine that were legally acquired from a New Mexico licensed retailer or wholesaler (but not to exceed one bottle per person at the table), for consumption with such customer's meal, provided that any such bottle is opened by an employee of the restaurant who is legally entitled to serve alcoholic beverages, and the restaurant may charge a corkage fee for each such bottle opened.</P>
                <HD SOURCE="HD1">Sec. 17-3-12: No Sales to Minors</HD>
                <P>No alcoholic beverages may be sold within the Santa Ana Indian Reservation to persons under the age of 21 years.</P>
                <HD SOURCE="HD1">Sec. 17-3-13: Hours and Days of Sale</HD>
                <P>Alcoholic beverages may be sold, offered for sale or consumed on licensed premises within the Santa Ana Indian Reservation at such hours as are established by the Licensee, but provided that in no event shall any such sales or consumption occur between the hours of 2:00 a.m. and 7:00 a.m. on any day.</P>
                <HD SOURCE="HD1">Sec. 17-3-14: Other Prohibitions on Sales</HD>
                <P>The Tribal Council may, by duly enacted resolution, establish other days on which or times at which sales or consumption of alcoholic beverages are not permitted within the Santa Ana Indian Reservation. The Council shall give notice of any such enactment promptly to all licensees within the Santa Ana Indian Reservation. In addition, the Governor of the Pueblo may, in the event of a bona fide emergency, and by written order, prohibit the sale of any alcoholic beverages within the Santa Ana Indian Reservation for a period of time not to exceed 48 hours. The Governor shall give prompt notice of such emergency order to all licensees within the Santa Ana Indian Reservation. No such emergency order may extend beyond 48 hours, unless during that time the Tribal Council meets and determines that the emergency requires a further extension of such order.</P>
                <HD SOURCE="HD1">Sec. 17-3-15: Location of Sales, Consumption</HD>
                <P>No person licensed to sell alcoholic beverages within the Santa Ana Indian Reservation shall make such sales except at the licensed premises specifically designated in such license. No person holding a premises license shall permit consumption of alcoholic beverages purchased from such licensee to occur off of the licensed premises; except that nothing herein shall prohibit a premises licensee from permitting a customer who has purchased a bottle of wine with a meal, but only partially consumed the contents of such bottle, from taking the partially consumed bottle off of the premises, after such bottle has been recorked by the licensee and placed in a sealed bag, to which a receipt for the purchase of the bottle has been affixed.</P>
                <HD SOURCE="HD1">Sec. 17-3-16: Sales to be Made by Adults</HD>
                <P>A. No person shall be employed as a server at a licensed premises unless within 30 days after such person's employment such person has obtained alcohol server training equivalent to that required under the laws of the State of New Mexico.</P>
                <P>
                    B. No person shall be employed to sell, serve or accept payment for any sale of alcoholic beverages, or to oversee or direct or have any other involvement in any such sale, within the Santa Ana Indian Reservation, who is less than 21 years of age, except that a premises licensee that operates a restaurant or other facility that is held out to the 
                    <PRTPAGE P="41986"/>
                    public as a place where meals are prepared and served may employ persons 19 years of age or older to sell or serve alcoholic beverages to persons who are also ordering food, provided that no person under the age of 21 shall be employed as a bartender by any licensee within Santa Ana Indian Reservation.
                </P>
                <HD SOURCE="HD1">Sec. 17-3-17: All Sales Cash</HD>
                <P>No licensee shall make any sale of any alcoholic beverages within the Santa Ana Indian Reservation without receiving payment therefor by cash, check, credit card, cash equivalent (such as gaming chips) or voucher issued by the licensee and specifically intended to be redeemable for alcoholic beverages, at or about the time the sale is made; provided, that nothing herein shall preclude a licensee from receiving a delivery of alcoholic beverages from a duly authorized wholesaler where arrangements have been made to pay for such delivery at a different time; and provided further that nothing herein shall preclude a licensee from allowing a customer to purchase more than one alcoholic beverage in sequence, and to pay for all such purchases at the conclusion thereof, so long as payment is made in full before the customer has left the licensed premises; and provided further that nothing herein shall prevent a licensee from distributing alcoholic beverages to customers without charge, so long as such distribution is not otherwise in violation of any provision of this Liquor Code.</P>
                <HD SOURCE="HD1">Sec. 17-3-18: Requirement of License</HD>
                <P>Any person who sells, offers for sale, stores or possesses for commercial purposes, or maintains premises for the consumption of alcoholic beverages within the Santa Ana Indian Reservation, must be duly licensed under the provisions of this Liquor Code.</P>
                <HD SOURCE="HD1">Sec. 17-3-19: Classes of Licenses</HD>
                <P>The following types or classes of licenses for the sale or distribution of alcoholic beverages within the Santa Ana Indian Reservation shall be permitted:</P>
                <P>A. Package license, which shall authorize the licensee to store, possess, sell and offer for sale alcoholic beverages in unopened containers, or in containers that may only be opened by employees of the licensee, for consumption only off the licensed premises.</P>
                <P>B. Premises license, which shall authorize the licensee to store, possess and sell alcoholic beverages for consumption on the licensed premises, and to permit such consumption on the licensed premises, provided that such license when held by an inn or hotel shall also permit the licensee to stock any individual guest room with alcoholic beverages contained in a compartment available to the registered guest to whom such room is rented and who is 21 years of age or older; and provided further that a premises licensee may allow a patron who has purchased a bottle of wine with a meal, but who has not consumed all of the contents of such bottle, to leave the premises with the partially filled bottle, after the bottle has been recorded and placed in a sealed bag by the licensee, with a receipt showing the customer's payment for the bottle attached to the bag.</P>
                <P>C. Special event license, which shall authorize the licensee to possess, distribute, sell and offer for sale alcoholic beverages for consumption only on the licensed premises, and to permit such consumption, but only for a bona fide special event, and only during the period or periods specified in such license, which period or periods shall be limited to the periods during which the special event is occurring and from beginning to end shall not exceed 72 hours.</P>
                <HD SOURCE="HD1">Sec. 17-3-20: Qualifications for License</HD>
                <P>A. No person shall be entitled to be issued a license under the provisions of this Liquor Code who has previously been the subject of any proceeding resulting in the revocation or the denial of a renewal of any license for the sale of alcoholic beverages issued by the Pueblo or by any state or other jurisdiction, or who has been convicted of any felony in any jurisdiction involving theft, corruption, dishonesty or embezzlement, or who has not at the time the application for license is submitted attained the age of 21 years, or who is otherwise determined by the Pueblo to be unfit to be licensed to sell alcoholic beverages, or whose spouse is a person not qualified to hold a license under the provisions of this section.</P>
                <P>B. No partnership or corporation shall be entitled to be issued a license under the provisions of this Liquor Code if any individual occupying any management or supervisory position within such corporation or partnership, or who sits on the management committee or board of directors or trustees thereof, or who holds or controls a financial interest of ten percent or more in such partnership or corporation, is a person who would not be entitled to be issued a license under the provisions of this section.</P>
                <P>C. No person shall be entitled to be issued a package or premises license hereunder unless such person has, by virtue of an approved lease or other valid interest in lands within the Santa Ana Indian Reservation, lawful entitlement to engage in a business within the Development Area with which such license would be compatible, and can demonstrate that such person is otherwise capable of complying with all of the requirements imposed on licensees by this Liquor Code.</P>
                <P>D. No application for a package or premises license shall be issued for any licensed premises outside of the Development Area.</P>
                <P>E. Notwithstanding anything in this section to the contrary, the Pueblo and its agencies, programs and enterprises shall be entitled to be issued licenses hereunder in appropriate circumstances, provided that all other provisions of this Liquor Code are complied with.</P>
                <HD SOURCE="HD1">Sec. 17-3-21: Package and Premises License Application; Procedure; Fees</HD>
                <P>A. Every person seeking a package or premises license under the provisions of this Liquor Code (other than the Pueblo or any of its agencies, programs or enterprises) shall submit to the Pueblo's Tribal Administrator, or such other person as the Governor may designate to handle such matters (hereinafter referred to as “Liquor License Administrator”) a written application, under oath, in the form prescribed by and containing the information required by this section.</P>
                <P>B. If the applicant is a natural person, the application shall contain, at a minimum, all of the following information:</P>
                <P>1. The full legal name of the applicant, plus any other names under which the applicant has been known or done business during the previous 20 years, and the applicant's date and place of birth, as shown by a certified copy of the applicant's birth certificate.</P>
                <P>2. The applicant's current legal residence address and business address, if any, and every residence address that the applicant has maintained during the previous ten years, with the dates during which each such address was current.</P>
                <P>3. The trade name, business address and description of every business in which the applicant has engaged or had any interest (other than stock ownership or partnership interest amounting to less than five percent of total capital) during the previous ten years, and the dates during which the applicant engaged in or held an interest in any such business.</P>
                <P>
                    4. A listing of every other jurisdiction in which the applicant has ever applied for a license to sell or distribute 
                    <PRTPAGE P="41987"/>
                    alcoholic beverages, the date on which each such application was filed, the name of the regulatory agency with which the application was filed, the action taken on each such application, and if any such license was issued, the dates during which it remained in effect, and as to each such license a statement whether any action was ever taken by the regulatory body to suspend or revoke such license, with full dates and details of any such incident.
                </P>
                <P>5. A listing of every crime with which the applicant has ever been charged, other than routine traffic offenses (but including any charge of driving while intoxicated or the like), giving as to each the date on which the charge was made, the location, the jurisdiction, the court in which the matter was heard, and the outcome or ultimate disposition thereof.</P>
                <P>6. The name and address of every person or entity holding any security interest in any of the assets of the business to be conducted by the applicant, or in any of the proceeds of such business.</P>
                <P>7. A detailed plat of the business premises within the Development Area, including the floor plans of any structure and the details of any exterior areas intended to be part of the licensed premises, together with evidence of the applicant's right to conduct business on such premises.</P>
                <P>8. A detailed description of the business conducted or intended to be conducted on the licensed premises and including (but not limited to) hours of operation and number of employees.</P>
                <P>9. The type(s) of license(s) requested.</P>
                <P>C. If the applicant is a corporation, the corporation, each officer of the corporation and every person holding 10% or more of the outstanding stock in the corporation shall submit an application complying with the provisions of paragraph B of this section, and in addition, the applicant shall also submit the following:</P>
                <P>1. A certified copy of its Articles of Incorporation and Bylaws.</P>
                <P>2. The names and addresses of all officers and directors and those stockholders owning 5% or more of the voting stock of the corporation and the amount of stock held by each such stockholder.</P>
                <P>3. The name of the resident agent of the corporation who would be authorized to accept service of process, including orders and notices issued by the Pueblo, and who will have principal supervisory responsibility for the business to be conducted on the licensed premises.</P>
                <P>4. Such additional information regarding the corporation as the Liquor License Administrator may require to assure a full disclosure of the corporation's structure and financial responsibility.</P>
                <P>D. If the applicant is a partnership, the partnership, the managing partner and every partner having an interest amounting to 10% or more of the total equity interest in the partnership shall submit applicants complying with the provisions of paragraph B of this section, and in addition, the applicant shall submit the following:</P>
                <P>1. A certified copy of the Partnership Agreement.</P>
                <P>2. The names and addresses of all general partners and of all limited partners contributing 10% or more of the total value of contributions made to the limited partnership or who are entitled to 10% or more of any distributions of the limited partnership.</P>
                <P>3. The name and address of the partner, or other agent of the partnership, authorized to accept service of process, including orders and notices issued by the Pueblo, and who will have principal supervisory responsibility for the business to be conducted in the licensed premises.</P>
                <P>4. Such additional information regarding the partnership as the Liquor License Administrator may require to assure a full disclosure of the partnership's structure and financial responsibility.</P>
                <P>E. Every applicant who is a natural person, and every person required by paragraphs C or D of this section to comply with the provisions of paragraph B, shall also submit with the application a complete set of fingerprints, taken under the supervision of and certified to by an officer of an authorized law enforcement agency located within the State of New Mexico.</P>
                <P>F. Every applicant for either a package license or a premises license shall submit with the completed license application a non-refundable license processing fee, in the amount set forth below:</P>
                <FP SOURCE="FP-1">Package license—$5,000.00</FP>
                <FP SOURCE="FP-1">Premises license—$1,000.00</FP>
                <P>In addition, each applicant shall pay a fee to cover the cost of a background investigation of each individual for whom such investigation must be undertaken in connection with the application, in an amount to be set by the Liquor License Administrator from time to time.</P>
                <P>G. Upon receiving a completed license application together with the required fee, the Liquor License Administrator shall cause a background investigation to be performed of the applicant, to determine whether the applicant is qualified to be licensed under the provisions of this Liquor Code. Upon the written recommendation of the Liquor License Administrator (if requested by the applicant), the Governor may, in his discretion, issue a preliminary license to the applicant effective for a period of no more than 90 days, but which shall be renewable for one additional period of 90 days in the event the background investigation cannot be completed within the first 90-day period; provided, however, that in no event shall the issuance of a preliminary license, or the renewal of such license for an additional 90-day period, entitle the applicant to favorable consideration with respect to the application for a package or premises license.</P>
                <P>H. The Pueblo or any of its agencies, programs or enterprises may apply for a package or premises license by submitting an application to the Liquor License Administrator identifying the applicant, describing in detail the purpose of the license, including a detailed description of the proposed licensed premises, and including the appropriate fee as set forth in Paragraph F of this section.</P>
                <HD SOURCE="HD1">Sec. 17-3-22: Issuance of License</HD>
                <P>A. The Liquor License Administrator shall, after reviewing all of the information submitted by the applicant or revealed by the background investigation, submit a report to the Governor recommending either approval or denial of the application for the license, and stating the reasons for such recommendation.</P>
                <P>B. Upon review of the recommendation of the Liquor License Administrator, if the Governor finds that the applicant satisfies the requirements of Sec. 17-3-20 of this Article, the Governor shall issue the license, authorizing the applicant to engage in sales of alcoholic beverages within the Santa Ana Indian Reservation as permitted by the class of license applied for, and specifying in detail the licensed premises where such sales are permitted (which shall be within the Development Area), but subject also to all the terms and conditions of this Liquor Code, and to such other appropriate conditions, not inconsistent with the provisions of this Liquor Code, as the Governor may deem reasonable and necessary under the circumstances.</P>
                <P>
                    C. In the event the Governor concludes, on the basis of the Liquor License Administrator's report, that the applicant does not satisfy the requirements of Sec. 17-3-20 of this Article, the Governor shall issue a 
                    <PRTPAGE P="41988"/>
                    notice denying the application, and explaining the basis for such denial.
                </P>
                <P>D. Any applicant whose application is denied shall have the right to appeal such denial, by filing a Notice of Appeal with the Office of the Governor and with the Santa Ana Tribal Court, within 30 days of the date of receipt of the Notice of Denial. Upon receiving a copy of a Notice of Appeal, the Governor's office shall prepare a copy of the entire file pertaining to the application and shall transmit it to the Tribal Court, with a copy to the applicant. The Pueblo, represented by the Pueblo's attorney, shall appear in the action in the Tribal Court. The proceedings in the Tribal Court shall be based upon the record that was before the Liquor License Administrator and the Governor, except that the applicant may, upon a showing of good cause, be permitted to submit additional evidence to rebut or explain information relied on by the Governor for his denial of the application that was not obtained from the applicant. The Tribal Court shall affirm the Governor's decision unless it finds that the Governor acted arbitrarily or capriciously or otherwise abused his discretion in making his determination.</P>
                <P>E. Any party that is aggrieved by the decision of the Tribal Court may petition the Tribal Council to review the Tribal Court decision, in writing, within 30 days after issuance of the Tribal Court decision. The petition shall set forth the specific grounds on which the petitioner claims the Tribal Court erred in its decision, and why its decision should be reviewed, and shall be served on the Governor and all parties. The prevailing party may submit a response to the petition within 15 days of service of the petition. The Governor shall place the petition on the agenda of the next Tribal Council meeting after service of the response (or the expiration of the 15-day period, if no response is filed), and the Tribal Council shall, at such meeting, decide whether to hear the petition. In the event the Tribal Council decides to hear the petition, the Governor shall notify all parties of that decision, and of the date on which the Tribal Council shall consider the matter. The Governor shall provide each Tribal Council member with a copy of the Tribal Court decision, the petition for Tribal Council review and the response, if any, and the complete record before the Tribal Court shall be available for inspection by any Tribal Council member. The Tribal Council shall hear each party's representative present its arguments and shall decide by majority vote whether a license should be issued to the applicant. The Tribal Council's decision shall be final and nonreviewable.</P>
                <HD SOURCE="HD1">Sec. 17-3-23: Term; Renewal; Fee</HD>
                <P>A. Each package or premises license issued hereunder shall have a term of one (1) year from the date of issuance, provided that such license shall be renewable for additional periods of one year each by any licensee who has complied fully with the terms and provisions of the license and of this Liquor Code during the term of the license, and who remains fully qualified to be licensed under the provisions of Sec. 17-3-20 of this Article, upon payment to the Pueblo of a license renewal fee in the amount of the initial application fee, and submission of an application for renewal on a form specified by the Liquor License Administrator, no less than thirty (30) days prior to the expiration date of the license. The renewal form shall require the applicant to note any changes in the information submitted with the original license application. The failure to submit a timely renewal application, with the required fee, may subject the licensee to a late charge of $500.00. If the renewal application is not submitted prior to expiration of the license, the Liquor License Administrator may treat the license as having expired and may require the licensee to file a new application in compliance with Sec. 17-3-21 of this Article.</P>
                <P>B. Upon receipt of an application for renewal of a license, and a recommendation of the Liquor License Administrator, the Governor shall determine whether the licensee has conducted its operations in compliance with the provisions of this Code and is otherwise qualified to be licensed. In the event the Governor receives information indicating that the licensee has not complied with the provisions of this Code or is otherwise not qualified to be licensed hereunder, the Governor shall deny the application for renewal, giving the licensee written notice thereof with a statement of the reasons for such denial.</P>
                <P>C. A licensee may appeal a denial of an application for renewal of its license, by filing a Notice of Appeal with the Office of the Governor and with the Santa Ana Tribal Court, within 30 days of receipt of the Notice of Denial of the application for renewal. Upon receiving the Notice of Appeal, the Governor's office shall prepare a complete copy of the entire file pertaining to the application and shall transmit it to the Tribal Court, with a copy to the applicant. The Pueblo, represented by the Pueblo's attorney, shall appear in the action in the Tribal Court. The proceedings in the Tribal Court shall be based upon the information submitted to the Governor by the licensee and any other information obtained by the Governor in the course of processing the application, except that the licensee shall be permitted to submit additional evidence to rebut or explain information relied on by the Governor for his denial of the application that was not obtained from the licensee. The licensee may apply to the Tribal Court for an order maintaining the license in effect during the pendency of the appeal, but in the absence of such order, the license shall expire at the end of its term. The Tribal Court shall affirm the Governor's decision unless it finds that the Governor acted arbitrarily or capriciously or otherwise abused his discretion in making his determination.</P>
                <P>D. Any party that is aggrieved by the decision of the Tribal Court may petition the Tribal Council to review the Tribal Court decision, in writing, within 30 days after issuance of the Tribal Court decision. The petition shall set forth the specific grounds on which the petitioner claims the Tribal Court erred in its decision, and why its decision should be reviewed, and shall be served on the Governor and all parties. The prevailing party may submit a response to the petition within 15 days of service of the petition. The Governor shall place the petition on the agenda of the next Tribal Council meeting after service of the response (or the expiration of the 15-day period, if no response is filed), and the Tribal Council shall, at such meeting, decide whether to hear the petition. In the event the Tribal Council decides to hear the petition, the Governor shall notify all parties of that decision, and of the date on which the Tribal Council shall consider the matter. The Governor shall provide each Tribal Council member with a copy of the Tribal Court decision, the petition for Tribal Council review and the response, if any, and the complete record before the Tribal Court shall be available for inspection by any Tribal Council member. The Tribal Council shall hear each party's representative present its argument and shall decide by majority vote whether the license should be renewed. The Tribal Council's decision shall be final and nonreviewable.</P>
                <HD SOURCE="HD1">Sec. 17-3-24: Conditions of License</HD>
                <P>
                    No licensee shall have any property interest in any license issued under the provisions of this Liquor Code, and every such license shall be deemed to confer a privilege, revocable by the Pueblo in accordance with the provisions of this Article. The continued validity of every package and 
                    <PRTPAGE P="41989"/>
                    premises license issued hereunder shall be dependent upon the following conditions:
                </P>
                <P>A. Every representation made by the licensee and any of its officers, directors, shareholders, partners or other persons required to submit information in support of the application, shall have been true at the time such information was submitted, and shall continue to be true, except to the extent the licensee advises the Liquor License Administrator in writing of any change in any such information, and notwithstanding any such change, the licensee shall continue to be qualified to be licensed under the provisions of this Liquor Code.</P>
                <P>B. The licensee shall at all times conduct its business on the Santa Ana Indian Reservation in full compliance with the provisions of this Liquor Code and with the other laws of the Pueblo.</P>
                <P>C. The licensee shall maintain in force, public liability insurance covering the licensed premises, insuring the licensee and the Pueblo against any claims, losses or liability whatsoever for any acts or omissions of the licensee or of any business invitee on the licensed premises resulting in injury, loss or damage to any other party, with coverage limits of at least $1 million per injured person, and the Liquor License Administrator shall at all times have written evidence of the continued existence of such policy of insurance.</P>
                <P>D. The licensee shall continue to have authority to engage in business within the Development Area, and shall have paid all required rentals, assessments, taxes, or other payments due the Pueblo.</P>
                <P>E. The business conducted on the licensed premises shall be conducted by the licensee or its employees directly, and shall not be conducted by any lessee, sublessee, assignee or other transferee, nor shall any license or any interest therein be sold, assigned, leased or otherwise transferred to any other person.</P>
                <P>F. All alcoholic beverages sold on the licensed premises shall have been obtained from a New Mexico licensed wholesaler.</P>
                <P>G. The licensee shall submit to the jurisdiction of the Tribal Court of the Pueblo with respect to any action brought by the Pueblo or any of its agencies or officials to enforce the provisions of this Liquor Code, or with respect to any action arising out of the licensee's sale or service of alcoholic beverages on the licensed premises.</P>
                <HD SOURCE="HD1">Sec. 17-3-25: Sanctions for Violation of License</HD>
                <P>A. Upon determining that any person licensed by the Pueblo to sell alcoholic beverages under the provisions of this Article is for any reason no longer qualified to hold such license under the provisions of Sec. 17-3-20 hereof, or has violated any of the conditions set forth in Sec. 17-3-24, the Governor shall immediately serve written notice upon such licensee directing that he show cause within ten (10) calendar days why his license should not be suspended or revoked, or a fine imposed. The notice shall specify the precise grounds relied upon and the action proposed.</P>
                <P>B. If the licensee fails to respond to such notice within ten (10) calendar days of service of such notice, the Governor shall issue an order suspending the license for such period as the Governor deems appropriate, or revoking the license, effective immediately, or imposing a fine, in such amount as the Governor deems reasonable. If the licensee, within the 10-day period, files with the Office of the Governor a written response and request for a hearing before the Santa Ana Tribal Court, such hearing shall be set no later than thirty (30) calendar days after receipt of such request.</P>
                <P>C. At the hearing, the licensee, who may be represented by counsel, shall present evidence and argument directed at the issue of whether or not the asserted grounds for the proposed action are in fact true, and whether such grounds justify such action. The Pueblo may present such other evidence as it deems appropriate.</P>
                <P>D. The court after considering all of the evidence and arguments shall issue a written decision either upholding the proposed action of the Governor, modifying such action by imposing some lesser penalty, or ruling in favor of the licensee, and such decision shall be final and conclusive.</P>
                <HD SOURCE="HD1">Sec. 17-3-26: Special Event License</HD>
                <P>A. Any person authorized to conduct business within the Development Area, or any established organization (including any agency, department or enterprise of the Pueblo) that includes any member of the Pueblo and that has authority to conduct any activities within the Santa Ana Indian Reservation, that is not a licensee hereunder and that has not had an application for a license rejected, may apply to the Liquor License Administrator for a special event license, which shall entitle the applicant to distribute alcoholic beverages, whether or not for consideration, in connection with a bona fide special event to be held by the applicant within the Development Area. Any such application must be filed in writing, in a form prescribed by the Liquor License Administrator, no later than ten (10) calendar days prior to the event, and must be accompanied by a fee in an amount set by the Liquor License Administrator from time to time, and must contain at least the following information:</P>
                <P>1. The exact days and times during which the event will occur (provided, that in no event shall any license be in effect for a period exceeding 72 hours, from the beginning of the first day of the event until the end of the last day);</P>
                <P>2. The precise location within the Development Area where the event will occur, and where alcoholic beverages will be distributed;</P>
                <P>3. The nature and purpose of the event, and the identity or categories of persons who are invited to participate;</P>
                <P>4. The nature of any food and beverages to be distributed, and the manner in which such distribution shall occur;</P>
                <P>5. Details of all provisions made by the applicant for sanitation, security and other measures to protect the health and welfare of participants at the event;</P>
                <P>6. Certification that the event will be covered by a policy of public liability insurance as described in Sec. 17-3-24(C) of this Liquor Code, that includes the Pueblo as a co-insured, or that the applicant will indemnify the Pueblo and hold it harmless from any claims, demands, liability or expense as a result of the act or omission of any person in connection with the special event, in which latter case the Liquor License Administrator or Governor may require a bond to assure compliance with such indemnification provision.</P>
                <P>7. Any other information required by the Liquor License Administrator relative to the event.</P>
                <P>B. The Liquor License Administrator, or the Governor, shall act to approve or reject the application no later than three days following submission of the application with the required fee. If the application is approved, the Liquor License Administrator or the Governor shall issue the license, which shall specify the hours during which and the premises within which sales, distribution and consumption of alcoholic beverages may occur. If any application is rejected, the rejection shall indicate the grounds therefor, and the applicant shall be entitled to file a new application correcting any deficiencies or problems found in the original application that warranted the rejection.</P>
                <P>
                    C. Alcoholic beverages may be sold or distributed pursuant to a special event license only at the location and during the hours specified in such license, in 
                    <PRTPAGE P="41990"/>
                    connection with the special event, only to participants in such special event, and only for consumption on the premises described in the license. Such sales or distribution must comply with any conditions imposed by the license, and with all other applicable provisions of this Liquor Code. All such alcoholic beverages must have been obtained from a New Mexico licensed wholesaler or retailer.
                </P>
                <HD SOURCE="HD1">Sec. 17-3-27: Display of License</HD>
                <P>Every person licensed by the Pueblo to sell alcoholic beverages within the Santa Ana Indian Reservation shall prominently display the license on the licensed premises during hours of operation.</P>
                <HD SOURCE="HD1">Sec. 17-3-28: Purchase From or Sale to Unauthorized Persons</HD>
                <P>Within the Santa Ana Indian Reservation, no person shall purchase any alcoholic beverage at retail except from a person licensed by the Pueblo under the provisions of this title; no person except a person licensed by the Pueblo under the provisions of this title shall sell any alcoholic beverage at retail; nor shall any person sell any alcoholic beverage for resale to any person other than a person properly licensed by the Pueblo under the provisions of this title.</P>
                <HD SOURCE="HD1">Sec. 17-3-29: Sale to Minors</HD>
                <P>A. No person shall sell or serve any alcoholic beverage to any person under the age of 21 years.</P>
                <P>B. It shall be a defense to an alleged violation of this Section that the purchaser presented to the seller or server an apparently valid identification document showing the purchaser's age to be 21 years or older, provided that the seller or server, as the case may be, had no actual or constructive knowledge of the falsity of the identification document, and relied in good faith on its apparent validity.</P>
                <HD SOURCE="HD1">Sec. 17-3-30: Purchase by Minor</HD>
                <P>No person under the age of 21 years shall purchase, attempt to purchase or possess any alcoholic beverage.</P>
                <HD SOURCE="HD1">Sec. 17-3-31: Sale to Person Under the Influence of Alcohol</HD>
                <P>No person shall sell any alcoholic beverage to a person who the seller has reason to believe is intoxicated or who the seller has reason to believe intends to provide such alcoholic beverage to an intoxicated person.</P>
                <HD SOURCE="HD1">Sec. 17-3-32: Purchase by Person Under the Influence of Alcohol</HD>
                <P>No intoxicated person shall purchase any alcoholic beverage.</P>
                <HD SOURCE="HD1">Sec. 17-3-33: Drinking in Public Places</HD>
                <P>No person shall consume any alcoholic beverage in any public place within the Santa Ana Indian Reservation except on premises licensed by the Pueblo for the sale of alcoholic beverages by the drink.</P>
                <HD SOURCE="HD1">Sec. 17-3-34: Bringing Liquor Onto Licensed Premises</HD>
                <P>No person shall bring any alcoholic beverage for personal consumption onto any premises within the Santa Ana Indian Reservation where liquor is authorized to be sold by the drink, unless such beverage was purchased on such premises, or unless the possession or distribution of such beverages on such premises is otherwise permitted under the provisions of this Liquor Code.</P>
                <HD SOURCE="HD1">Sec. 17-3-35: Open Containers Prohibited</HD>
                <P>No person shall have an open container of any alcoholic beverage in a public place, other than on premises licensed for the sale of alcoholic beverages by the drink, or in any automobile, whether moving or standing still. This Section shall not apply to empty containers such as aluminum cans or glass bottles collected for recycling.</P>
                <HD SOURCE="HD1">Sec. 17-3-36: Use of False or Altered Identification</HD>
                <P>No person shall purchase or attempt to purchase any alcoholic beverage by the use of any false or altered identification document that falsely purports to show the individual to be 21 years of age or older.</P>
                <HD SOURCE="HD1">Sec. 17-3-37: Penalties</HD>
                <P>A. Any person convicted of committing any violation of this Article shall be subject to punishment of up to one (1) year imprisonment or a fine not to exceed Five Thousand Dollars ($5,000.00), or to both such imprisonment and fine.</P>
                <P>B. Any person not a member of the Pueblo, upon committing any violation of any provision of this Article, may be subject to a civil action for trespass, and upon having been determined by the court to have committed the alleged violation, shall be found to have trespassed upon the lands of the Pueblo, and shall be assessed such damages as the court deems appropriate in the circumstances.</P>
                <P>C. Any person suspected of having violated any provision of this Article shall, in addition to any other penalty imposed hereunder, be required to surrender any alcoholic beverages in such person's possession to the officer making the arrest or issuing the complaint.</P>
                <HD SOURCE="HD1">Sec. 17-3-38: Jurisdiction</HD>
                <P>Any and all actions, whether civil or criminal, arising from or pertaining to alleged violations of this title or any duty imposed hereby, or seeking any relief against the Pueblo or any officer or employee of the Pueblo with respect to any matter addressed by this Liquor Code, shall be brought in the Tribal Court of the Pueblo, which court shall have exclusive jurisdiction thereof. No waiver of this provision shall be implied by any court, and no such waiver shall be valid unless expressly set forth in a written resolution of the Tribal Council.</P>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10525 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4337-15-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF THE INTERIOR</AGENCY>
                <SUBAGY>Bureau of Land Management</SUBAGY>
                <DEPDOC>[LLHQ310000.L13100000.PP0000; OMB Control No. 1004-0034]</DEPDOC>
                <SUBJECT>Agency Information Collection Activities; Submission to the Office of Management and Budget for Review and Approval; Oil and Gas, or Geothermal Resources: Transfers and Assignments</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Bureau of Land Management, Interior.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of information collection; request for comment.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>In accordance with the Paperwork Reduction Act of 1995 (PRA), the Bureau of Land Management (BLM) proposes to renew with changes an information collection.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Interested persons are invited to submit comments on or before June 13, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Written comments and recommendations for this information collection request (ICR) should be sent within 30 days of publication of this notice to 
                        <E T="03">www.reginfo.gov/public/do/PRAMain.</E>
                         Find this information collection by selecting “Currently under 30-day Review—Open for Public Comments” or by using the search function.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        To request additional information about this ICR, contact Peter Cowan by email at 
                        <E T="03">picowan@blm.gov,</E>
                         or by telephone at 
                        <PRTPAGE P="41991"/>
                        720-838-1641. Individuals in the United States who are deaf, deafblind, hard of hearing, or have a speech disability may dial 711 (TTY, TDD, or TeleBraille) to access telecommunications relay services. Individuals outside the United States should use the relay services offered within their country to make international calls to the point-of-contact in the United States. You may also view the ICR at 
                        <E T="03">http://www.reginfo.gov/public/do/PRAMain.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    In accordance with the PRA (44 U.S.C. 3501 
                    <E T="03">et seq.</E>
                    ) and 5 CFR 1320.8(d)(1), we invite the public and other Federal agencies to comment on new, proposed, revised and continuing collections of information. This helps the BLM assess impacts of its information collection requirements and minimize the public's reporting burden. It also helps the public understand BLM information collection requirements and ensure requested data are provided in the desired format.
                </P>
                <P>
                    A 
                    <E T="04">Federal Register</E>
                     notice with a 60-day public comment period soliciting comments on this collection of information was published on November 7, 2023 (88 FR 76846).
                </P>
                <P>As part of our continuing effort to reduce paperwork and respondent burdens, we are again inviting the public and other Federal agencies to comment on the proposed ICR described below. The BLM is especially interested in public comment addressing the following:</P>
                <P>(1) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility.</P>
                <P>(2) The accuracy of our estimate of the burden for this collection of information, including the validity of the methodology and assumptions used.</P>
                <P>(3) Ways to enhance the quality, utility, and clarity of the information to be collected; and</P>
                <P>
                    (4) How might the agency minimize the burden of the collection of information on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, 
                    <E T="03">e.g.,</E>
                     permitting electronic submission of response.
                </P>
                <P>Comments submitted in response to this notice are a matter of public record. Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.</P>
                <P>
                    <E T="03">Abstract:</E>
                     This collection of information enables the BLM to process assignments of record title interest and transfers of operating rights in a lease for oil and gas or geothermal resources. Each assignment or transfer is a contract between private parties but, by law, must be approved by the Secretary. The BLM uses information about assignments and transfers to prevent unlawful extraction of mineral resources, to ensure prompt payment of rentals and royalties for the rights obtained under a Federal lease, and to ensure that leases are not encumbered with agreements that cause the minerals to be uneconomical to produce, resulting in lost revenues to the Federal Government. The information also enables the BLM to ensure the assignee or transferee is in compliance with the bonding requirements, when necessary, before approval of the transfer or assignment. The BLM does not expect any changes to the burden hours for submissions; however, the BLM did update the information to be collected. The BLM added the legacy lease serial number field to capture the legacy serial number now that all leases have a new serial number based upon all records migrating into the Mineral &amp; Land Records System. The BLM will also require the forms to include a company's principals, as defined under 2 CFR 180.995. The BLM requires the principal information to ensure the entity acquiring interest in the lease is not Federally suspended or debarred and is qualified to hold a lease. The BLM does not expect these additional fields to increase the burden as this information is readily available. Additionally, The BLM is adjusting the cost burden to reflect inflation adjustments. This adjustment will increase the total annual cost burden by $132,270 (from $881,800 to $1,014,070). OMB control number 1004-0034 is currently scheduled to expire on September 30, 2024. The BLM plans to request that OMB renew this OMB control number for an additional thee (3) years.
                </P>
                <P>
                    <E T="03">Title of Collection:</E>
                     Oil and Gas, or Geothermal Resources: Transfers and Assignments (43 CFR Subparts 3106, 3135, and 3216).
                </P>
                <P>
                    <E T="03">OMB Control Number:</E>
                     1004-0034.
                </P>
                <P>
                    <E T="03">Form Number:</E>
                     3000-003; 3000-003a.
                </P>
                <P>
                    <E T="03">Type of Review:</E>
                     Extension with revision of a currently approved collection.
                </P>
                <P>
                    <E T="03">Respondents/Affected Public:</E>
                     Assignors and assignees of record title interest in a lease for oil and gas or geothermal resources; and transferors and transferees of operating rights (sublease) in a lease for oil and gas or geothermal resources.
                </P>
                <P>
                    <E T="03">Total Estimated Number of Annual Respondents:</E>
                     8,818.
                </P>
                <P>
                    <E T="03">Total Estimated Number of Annual Responses:</E>
                     8,818.
                </P>
                <P>
                    <E T="03">Estimated Completion Time per Response:</E>
                     30 minutes.
                </P>
                <P>
                    <E T="03">Total Estimated Number of Annual Burden Hours:</E>
                     4,410.
                </P>
                <P>
                    <E T="03">Respondent's Obligation:</E>
                     Required to obtain or retain a benefit.
                </P>
                <P>
                    <E T="03">Frequency of Collection:</E>
                     On occasion.
                </P>
                <P>
                    <E T="03">Total Estimated Annual Nonhour Burden Cost:</E>
                     $1,014,070.
                </P>
                <P>An agency may not conduct or sponsor and, notwithstanding any other provision of law, a person is not required to respond to a collection of information unless it displays a currently valid OMB control number.</P>
                <P>
                    The authority for this action is the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 
                    <E T="03">et seq.</E>
                    ).
                </P>
                <SIG>
                    <NAME>Darrin King,</NAME>
                    <TITLE>Information Collection Clearance Officer.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10434 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4310-84-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF THE INTERIOR</AGENCY>
                <SUBAGY>National Park Service</SUBAGY>
                <DEPDOC>[NPS-WASO-NRNHL-DTS#-37949; PPWOCRADI0, PCU00RP14.R50000]</DEPDOC>
                <SUBJECT>National Register of Historic Places; Notification of Pending Nominations and Related Actions</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>National Park Service, Interior.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The National Park Service is soliciting electronic comments on the significance of properties nominated before May 4, 2024, for listing or related actions in the National Register of Historic Places.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Comments should be submitted electronically by May 29, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Comments are encouraged to be submitted electronically to 
                        <E T="03">National_Register_Submissions@nps.gov</E>
                         with the subject line “Public Comment on &lt;property or proposed district name, (County) State&gt;.” If you have no access to email, you may send them via U.S. Postal Service and all other carriers to the National Register of 
                        <PRTPAGE P="41992"/>
                        Historic Places, National Park Service, 1849 C Street NW, MS 7228, Washington, DC 20240.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Sherry A. Frear, Chief, National Register of Historic Places/National Historic Landmarks Program, 1849 C Street NW, MS 7228, Washington, DC 20240, 
                        <E T="03">sherry_frear@nps.gov,</E>
                         202-913-3763.
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P/>
                <P>The properties listed in this notice are being considered for listing or related actions in the National Register of Historic Places. Nominations for their consideration were received by the National Park Service before May 4, 2024. Pursuant to section 60.13 of 36 CFR part 60, comments are being accepted concerning the significance of the nominated properties under the National Register criteria for evaluation.</P>
                <P>Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.</P>
                <P>Nominations submitted by State or Tribal Historic Preservation Officers</P>
                <P>
                    <E T="03">Key:</E>
                     State, County, Property Name, Multiple Name(if applicable), Address/Boundary, City, Vicinity, Reference Number.
                </P>
                <EXTRACT>
                    <HD SOURCE="HD1">ALABAMA</HD>
                    <HD SOURCE="HD1">Colbert County</HD>
                    <FP SOURCE="FP-1">Memphis &amp; Charleston Railroad Bridge, 2106 Ashe Boulevard, Sheffield, SG100010428</FP>
                    <HD SOURCE="HD1">Coosa County</HD>
                    <FP SOURCE="FP-1">Weogufka State Park, CCC Camp Road approx., 1.3 miles southeast of intersection with Lay Dam Road, Weogufka vicinity, SG100010427</FP>
                    <HD SOURCE="HD1">DISTRICT OF COLUMBIA</HD>
                    <HD SOURCE="HD1">District of Columbia</HD>
                    <FP SOURCE="FP-1">Old Chinese Legation, 2001 19th Street NW, Washington, SG100010419</FP>
                    <HD SOURCE="HD1">KANSAS</HD>
                    <HD SOURCE="HD1">Reno County</HD>
                    <FP SOURCE="FP-1">Hotel Stamey, 501 N Main, Hutchinson, SG100010420</FP>
                    <HD SOURCE="HD1">Wyandotte County</HD>
                    <FP SOURCE="FP-1">Schmotz, Frank and Agnes, Farmstead, (Agriculture-Related Resources of Kansas MPS), 643 South 138th Street, Bonner Springs, MP100010423</FP>
                    <FP SOURCE="FP-1">Downtown Kansas City Kansas Historic District, located east of the Missouri River, on the western border of Kansas City, Kansas where Interstate 70 connects to the Downtown area through on/off ramps onto Minnesota Avenue and Washington Blvd., Kansas City, SG100010431</FP>
                    <HD SOURCE="HD1">MAINE</HD>
                    <HD SOURCE="HD1">Somerset County</HD>
                    <FP SOURCE="FP-1">Maine Women's Reformatory Maternity Hospital and Nursery, 26 Mary Street, Skowhegan, SG100010425</FP>
                    <HD SOURCE="HD1">NEW YORK</HD>
                    <HD SOURCE="HD1">Bronx County</HD>
                    <FP SOURCE="FP-1">Edenwald Houses, Generally bounded by Grenada Place, Baychester Avenue, East 225th Street, Laconia Avenue, and Schieffelin Avenue, Bronx, SG100010433</FP>
                    <HD SOURCE="HD1">New York County</HD>
                    <FP SOURCE="FP-1">Manhattanville Houses, 3224-3250 Broadway, 545-555 West 126th Street. 1414-1470 Amsterdam Avenue, 556-578 West 131th Street. 500-520 West 133th Street, New York, SG100010432</FP>
                    <HD SOURCE="HD1">PENNSYLVANIA</HD>
                    <HD SOURCE="HD1">Wayne County</HD>
                    <FP SOURCE="FP-1">Bethany Presbyterian Church, 431 Wayne Street, Bethany, SG100010411</FP>
                    <HD SOURCE="HD1">SOUTH CAROLINA</HD>
                    <HD SOURCE="HD1">Darlington County</HD>
                    <FP SOURCE="FP-1">Darlington Theatre, 108 Pearl Street, Darlington, SG100010415</FP>
                    <HD SOURCE="HD1">TEXAS</HD>
                    <HD SOURCE="HD1">Hays County</HD>
                    <FP SOURCE="FP-1">Wimberley Downtown Square Historic District, Roughly bounded by Cypress Creek, Old Kyle Road, Henson Road, and Rio Bonlo Road, Wimberley, SG100010422</FP>
                </EXTRACT>
                <P>An additional documentation has been received for the following resource(s):</P>
                <EXTRACT>
                    <HD SOURCE="HD1">TENNESSEE</HD>
                    <HD SOURCE="HD1">Franklin County</HD>
                    <FP SOURCE="FP-1">Zaugg Bank Barn (Additional Documentation), 831 Crawford Ln., Belvidere vicinity, AD73001764</FP>
                    <HD SOURCE="HD1">Knox County</HD>
                    <FP SOURCE="FP-1">Lamar House Hotel (Additional Documentation), 803 Gay St., SW, Knoxville, AD75001763</FP>
                </EXTRACT>
                <P>Nomination(s) submitted by Federal Preservation Officers:</P>
                <P>The State Historic Preservation Officer reviewed the following nomination(s) and responded to the Federal Preservation Officer within 45 days of receipt of the nomination(s) and supports listing the properties in the National Register of Historic Places.</P>
                <EXTRACT>
                    <HD SOURCE="HD1">PUERTO RICO</HD>
                    <HD SOURCE="HD1">Rio Grande Municipality</HD>
                    <FP SOURCE="FP-1">Mt. Britton Tower, (New Deal Era Constructions in the Forest Reserves in Puerto Rico), 181 meters southeast of FS Road 10 at km. 1.3, Rio Grande vicinity, MP100010421</FP>
                </EXTRACT>
                <P>
                    <E T="03">Authority:</E>
                     Section 60.13 of 36 CFR part 60.
                </P>
                <SIG>
                    <NAME>Sherry A. Frear,</NAME>
                    <TITLE>Chief, National Register of Historic Places/National Historic Landmarks Program.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10494 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4312-52-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF THE INTERIOR</AGENCY>
                <SUBAGY>Bureau of Reclamation</SUBAGY>
                <DEPDOC>[RR04084000, XXXR4081X1, RN.20350030.0010054]</DEPDOC>
                <SUBJECT>Colorado River Basin Salinity Control Advisory Council Notice of Public Meeting</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Bureau of Reclamation, Interior.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of public meeting.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Bureau of Reclamation is publishing this notice to announce that a Federal Advisory Committee meeting of the Colorado River Basin Salinity Control Advisory Council (Council) will take place.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The meeting will take place in-person and virtually on the following two days: Wednesday, June 5, 2024, from 1:30 p.m. to approximately 5:00 p.m. (MDT), and Thursday, June 6, 8:30 a.m. to 12:00 p.m.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        The in-person meeting will be held at the Holiday Inn &amp; Suites, 21636 Highway US-160 West, Durango, Colorado 81301. To access the meeting virtually, please contact Clarence Fullard; see 
                        <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                        .
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Clarence Fullard, telephone (303) 253-1042; email at 
                        <E T="03">cfullard@usbr.gov.</E>
                         Individuals who are deaf, deafblind, hard of hearing, or have a speech disability may dial 711 (TTY, TDD, or TeleBraille) to access telecommunications relay services. Individuals outside the United States should use the relay services offered within their country to make international calls to the point-of-contact in the United States.
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The meeting of the Council is being held under the provisions of the Federal Advisory Committee Act of 1972. The Council was established by the Colorado River Basin Salinity Control Act of 1974 (Pub. L. 93-320) (Act) to receive reports and advise Federal agencies on implementing the Act.</P>
                <P>
                    <E T="03">Purpose of the Meeting:</E>
                     The purpose of the meeting is to discuss the accomplishments of Federal agencies and make recommendations on future 
                    <PRTPAGE P="41993"/>
                    activities to control salinity in the Colorado River Basin.
                </P>
                <P>
                    <E T="03">Agenda:</E>
                     Council members will be briefed on the status of salinity control activities. Discussions about salinity control research studies will occur. The Bureau of Reclamation, Bureau of Land Management, U.S. Fish and Wildlife Service, and United States Geological Survey of the Department of the Interior; the Natural Resources Conservation Service of the Department of Agriculture; and the Environmental Protection Agency will each present a progress report and a schedule of activities on salinity control in the Colorado River Basin. The Council will discuss salinity control activities, the contents of the reports, and the Basin States Program created by Public Law 110-246, which amended the Act. A final agenda will be posted online at 
                    <E T="03">https://www.usbr.gov/uc/progact/salinity/</E>
                     at least one week prior to the meeting.
                </P>
                <P>
                    <E T="03">Meeting Accessibility/Special Accommodations:</E>
                     The meeting is open to the public. Please make requests in advance for sign language interpreter services, assistive listening devices, or other reasonable accommodations. We ask that you contact Clarence Fullard (see 
                    <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                     section of this notice) at least seven (7) business days prior to the meeting to give the Department of the Interior sufficient time to process your request. All reasonable accommodation requests are managed on a case-by-case basis.
                </P>
                <P>
                    Individuals wanting virtual access to the meeting or those requiring special accommodations should contact Clarence Fullard (see 
                    <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                    ) no later than May 23, 2024, to receive instructions.
                </P>
                <P>
                    <E T="03">Public Comments:</E>
                     The Council chairman will provide time for oral comments from members of the public at the meeting. Individuals wanting to make an oral comment should contact Clarence Fullard (see 
                    <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                    ) to be placed on the public comment list. Members of the public may also file written statements with the Council before, during, or up to 30 days after the meeting either in person or by mail. To allow full consideration of information by Council members at this meeting, written comments must be provided to Clarence Fullard (see 
                    <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                    ) by May 23, 2024.
                </P>
                <P>
                    <E T="03">Public Disclosure of Personal Information:</E>
                     Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.
                </P>
                <P>
                    <E T="03">Authority:</E>
                     5 U.S.C. ch. 10.
                </P>
                <SIG>
                    <NAME>Wayne Pullan,</NAME>
                    <TITLE>Regional Director, Upper Colorado Basin—Interior Region 7, Bureau of Reclamation.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10467 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4332-90-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">INTERNATIONAL TRADE COMMISSION</AGENCY>
                <DEPDOC>[Investigation Nos. 701-TA-694 and 731-TA-1641-1642 (Final)]</DEPDOC>
                <SUBJECT>Aluminum Lithographic Printing Plates From China and Japan; Scheduling of the Final Phase of Antidumping and Countervailing Duty Investigations</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>United States International Trade Commission.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Commission hereby gives notice of the scheduling of the final phase of antidumping and countervailing duty investigation Nos. 701-TA-694 and 731-TA-1641-1642 (Final) pursuant to the Tariff Act of 1930 (“the Act”) to determine whether an industry in the United States is materially injured or threatened with material injury, or the establishment of an industry in the United States is materially retarded, by reason of imports of aluminum lithographic printing plates from China and Japan, provided for in subheading 3701.30.00 of the Harmonized Tariff Schedule of the United States, preliminarily determined by the Department of Commerce (“Commerce”) to be subsidized by the government of China and sold at less-than-fair-value.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>May 1, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Celia Feldpausch (202) 205-2387, Office of Investigations, U.S. International Trade Commission, 500 E Street SW, Washington, DC 20436. Hearing-impaired persons can obtain information on this matter by contacting the Commission's TDD terminal on 202-205-1810. Persons with mobility impairments who will need special assistance in gaining access to the Commission should contact the Office of the Secretary at 202-205-2000. General information concerning the Commission may also be obtained by accessing its internet server (
                        <E T="03">https://www.usitc.gov</E>
                        ). The public record for these investigations may be viewed on the Commission's electronic docket (EDIS) at 
                        <E T="03">https://edis.usitc.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P/>
                <P>
                    <E T="03">Scope.</E>
                    —For purposes of these investigations, Commerce has defined the subject merchandise as “. . . aluminum lithographic printing plates. Aluminum lithographic printing plates consist of a flat substrate containing at least 90 percent aluminum. The aluminum-containing substrate is generally treated using a mechanical, electrochemical, or chemical graining process, which is followed by one or more anodizing treatments that form a hydrophilic layer on the aluminum-containing substrate. An image-recording, oleophilic layer that is sensitive to light, including but not limited to ultra-violet, visible, or infrared, is dispersed in a polymeric binder material that is applied on top of the hydrophilic layer, generally on one side of the aluminum lithographic printing plate. The oleophilic light-sensitive layer is capable of capturing an image that is transferred onto the plate by either light or heat. The image applied to an aluminum lithographic printing plate facilitates the production of newspapers, magazines, books, yearbooks, coupons, packaging, and other printed materials through an offset printing process, where an aluminum lithographic printing plate facilitates the transfer of an image onto the printed media. Aluminum lithographic printing plates within the scope of these investigations include all aluminum lithographic printing plates, irrespective of the dimensions or thickness of the underlying aluminum substrate, whether the plate requires processing after an image is applied to the plate, whether the plate is ready to be mounted to a press and used in printing operations immediately after an image is applied to the plate, or whether the plate has been exposed to light or heat to create an image on the plate or remains unexposed and is free of any image.
                </P>
                <P>Subject merchandise also includes aluminum lithographic printing plates produced from an aluminum sheet coil that has been coated with a light-sensitive image recording layer in a subject country and that is subsequently unwound and cut to the final dimensions to produce a finished plate in a third country (including the United States), or exposed to light or heat to create an image on the plate in a third country (including in a foreign trade zone within the United States).</P>
                <P>
                    Excluded from the scope of these investigations are lithographic printing 
                    <PRTPAGE P="41994"/>
                    plates manufactured using a substrate produced from a material other than aluminum, such as rubber or plastic. Aluminum lithographic printing plates are currently classifiable under Harmonized Tariff of the United States (HTSUS) subheadings 3701.30.0000 and 3701.99.6060.
                </P>
                <P>Further, merchandise that falls within the scope of these investigations may also be entered into the United States under HTSUS subheadings 3701.99.3000 and 8442.50.1000. Although the HTSUS subheadings are provided for convenience and customs purposes, the written description of the scope of these investigations is dispositive.”</P>
                <P>
                    <E T="03">Background.</E>
                    —The final phase of these investigations is being scheduled pursuant to sections 705(b) and 731(b) of the Tariff Act of 1930 (19 U.S.C. 1671d(b) and 1673d(b)), as a result of affirmative preliminary determinations by Commerce that certain benefits which constitute subsidies within the meaning of § 703 of the Act (19 U.S.C. 1671b) are being provided to manufacturers, producers, or exporters in China of aluminum lithographic printing plates, and that imports of such products from China and Japan are being sold in the United States at less than fair value within the meaning of § 733 of the Act (19 U.S.C. 1673b). The investigations were requested in petitions filed on September 28, 2023, by Eastman Kodak Company, Rochester, New York.
                </P>
                <P>For further information concerning the conduct of this phase of the investigations, hearing procedures, and rules of general application, consult the Commission's Rules of Practice and Procedure, part 201, subparts A and B (19 CFR part 201), and part 207, subparts A and C (19 CFR part 207).</P>
                <P>
                    <E T="03">Participation in the investigations and public service list.</E>
                    —Persons, including industrial users of the subject merchandise and, if the merchandise is sold at the retail level, representative consumer organizations, wishing to participate in the final phase of these investigations as parties must file an entry of appearance with the Secretary to the Commission, as provided in § 201.11 of the Commission's rules, no later than 21 days prior to the hearing date specified in this notice. A party that filed a notice of appearance during the preliminary phase of the investigations need not file an additional notice of appearance during this final phase. The Secretary will maintain a public service list containing the names and addresses of all persons, or their representatives, who are parties to the investigations.
                </P>
                <P>
                    Please note the Secretary's Office will accept only electronic filings during this time. Filings must be made through the Commission's Electronic Document Information System (EDIS, 
                    <E T="03">https://edis.usitc.gov</E>
                    ). No in-person paper-based filings or paper copies of any electronic filings will be accepted until further notice.
                </P>
                <P>
                    <E T="03">Limited disclosure of business proprietary information (BPI) under an administrative protective order (APO) and BPI service list.</E>
                    —Pursuant to § 207.7(a) of the Commission's rules, the Secretary will make BPI gathered in the final phase of these investigations available to authorized applicants under the APO issued in the investigations, provided that the application is made no later than 21 days prior to the hearing date specified in this notice. Authorized applicants must represent interested parties, as defined by 19 U.S.C. 1677(9), who are parties to the investigations. A party granted access to BPI in the preliminary phase of the investigations need not reapply for such access. A separate service list will be maintained by the Secretary for those parties authorized to receive BPI under the APO.
                </P>
                <P>
                    <E T="03">Staff report.</E>
                    —The prehearing staff report in the final phase of these investigations will be placed in the nonpublic record on August 28, 2024, and a public version will be issued thereafter, pursuant to § 207.22 of the Commission's rules.
                </P>
                <P>
                    <E T="03">Hearing.</E>
                    —The Commission will hold a hearing in connection with the final phase of these investigations beginning at 9:30 a.m. on Thursday, September 12, 2024. Requests to appear at the hearing should be filed in writing with the Secretary to the Commission on or before Friday, September 6, 2024. Any requests to appear as a witness via videoconference must be included with your request to appear. Requests to appear via videoconference must include a statement explaining why the witness cannot appear in person; the Chairman, or other person designated to conduct the investigations, may in their discretion for good cause shown, grant such a request. Requests to appear as remote witness due to illness or a positive COVID-19 test result may be submitted by 3pm the business day prior to the hearing. Further information about participation in the hearing will be posted on the Commission's website at 
                    <E T="03">https://www.usitc.gov/calendarpad/calendar.html.</E>
                </P>
                <P>
                    A nonparty who has testimony that may aid the Commission's deliberations may request permission to present a short statement at the hearing. All parties and nonparties desiring to appear at the hearing and make oral presentations should attend a prehearing conference, if deemed necessary, to be held at 9:30 a.m. on Tuesday, September 10, 2024. Parties shall file and serve written testimony and presentation slides in connection with their presentation at the hearing by no later than 4:00 p.m. on September 11, 2024 (one business day prior to hearing). Oral testimony and written materials to be submitted at the public hearing are governed by sections 201.6(b)(2), 201.13(f), and 207.24 of the Commission's rules. Parties must submit any request to present a portion of their hearing testimony 
                    <E T="03">in camera</E>
                     no later than 7 business days prior to the date of the hearing.
                </P>
                <P>
                    <E T="03">Written submissions.</E>
                    —Each party who is an interested party shall submit a prehearing brief to the Commission. Prehearing briefs must conform with the provisions of § 207.23 of the Commission's rules; the deadline for filing is September 5, 2024. Parties shall also file written testimony in connection with their presentation at the hearing, and posthearing briefs, which must conform with the provisions of § 207.25 of the Commission's rules. The deadline for filing posthearing briefs is September 19, 2024. In addition, any person who has not entered an appearance as a party to the investigations may submit a written statement of information pertinent to the subject of the investigations, including statements of support or opposition to the petitions, on or before September 19, 2024. On October 4, 2024, the Commission will make available to parties all information on which they have not had an opportunity to comment. Parties may submit final comments on this information on or before October 8, 2024, but such final comments must not contain new factual information and must otherwise comply with § 207.30 of the Commission's rules. All written submissions must conform with the provisions of § 201.8 of the Commission's rules; any submissions that contain BPI must also conform with the requirements of §§ 201.6, 207.3, and 207.7 of the Commission's rules. The Commission's 
                    <E T="03">Handbook on Filing Procedures,</E>
                     available on the Commission's website at 
                    <E T="03">https://www.usitc.gov/documents/handbook_on_filing_procedures.pdf,</E>
                     elaborates upon the Commission's procedures with respect to filings.
                </P>
                <P>
                    Additional written submissions to the Commission, including requests pursuant to § 201.12 of the Commission's rules, shall not be accepted unless good cause is shown for accepting such submissions, or unless 
                    <PRTPAGE P="41995"/>
                    the submission is pursuant to a specific request by a Commissioner or Commission staff.
                </P>
                <P>In accordance with §§ 201.16(c) and 207.3 of the Commission's rules, each document filed by a party to the investigations must be served on all other parties to the investigations (as identified by either the public or BPI service list), and a certificate of service must be timely filed. The Secretary will not accept a document for filing without a certificate of service.</P>
                <P>
                    <E T="03">Authority:</E>
                     These investigations are being conducted under authority of title VII of the Tariff Act of 1930; this notice is published pursuant to § 207.21 of the Commission's rules.
                </P>
                <SIG>
                    <P>By order of the Commission.</P>
                    <DATED>Issued: May 9, 2024.</DATED>
                    <NAME>Lisa Barton,</NAME>
                    <TITLE>Secretary to the Commission.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10502 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 7020-02-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF LABOR</AGENCY>
                <SUBJECT>Agency Information Collection Activities; Submission for OMB Review; Comment Request; Proximity Detection Systems for Continuous Mining Machines in Underground Coal Mines</SUBJECT>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of availability; request for comments.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Department of Labor (DOL) is submitting this Mine Safety and Health Administration (MSHA)-sponsored information collection request (ICR) to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995 (PRA). Public comments on the ICR are invited.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The OMB will consider all written comments that the agency receives on or before June 13, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Written comments and recommendations for the proposed information collection should be sent within 30 days of publication of this notice to 
                        <E T="03">www.reginfo.gov/public/do/PRAMain.</E>
                         Find this particular information collection by selecting “Currently under 30-day Review—Open for Public Comments” or by using the search function.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Michael Howell by telephone at 202-693-6782, or by email at 
                        <E T="03">DOL_PRA_PUBLIC@dol.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    This proposed information collection requires underground coal mine operators to equip continuous mining machines, except full-face continuous mining machines, with proximity detection systems (80 FR 2188). Miners working near continuous mining machines face pinning, crushing, and striking hazards that result in accidents involving life-threatening injuries and death. Proximity detection is a technology that uses electronic sensors to detect the motion or the location of one object relative to another. Proximity detection systems provide a warning and stop mining machines before a pinning, crushing, or striking accident occurs that could result in injury or death to a miner. For additional substantive information about this ICR, see the related notice published in the 
                    <E T="04">Federal Register</E>
                     on January 22, 2024 (89 FR 3951).
                </P>
                <P>Comments are invited on: (1) whether the collection of information is necessary for the proper performance of the functions of the Department, including whether the information will have practical utility; (2) the accuracy of the agency's estimates of the burden and cost of the collection of information, including the validity of the methodology and assumptions used; (3) ways to enhance the quality, utility and clarity of the information collection; and (4) ways to minimize the burden of the collection of information on those who are to respond, including the use of automated collection techniques or other forms of information technology.</P>
                <P>
                    This information collection is subject to the PRA. A Federal agency generally cannot conduct or sponsor a collection of information, and the public is generally not required to respond to an information collection, unless the OMB approves it and displays a currently valid OMB Control Number. In addition, notwithstanding any other provisions of law, no person shall generally be subject to penalty for failing to comply with a collection of information that does not display a valid OMB Control Number. 
                    <E T="03">See</E>
                     5 CFR 1320.5(a) and 1320.6.
                </P>
                <P>
                    <E T="03">Agency:</E>
                     DOL-MSHA.
                </P>
                <P>
                    <E T="03">Title of Collection:</E>
                     Proximity Detection Systems for Continuous Mining Machines in Underground Coal Mines.
                </P>
                <P>
                    <E T="03">OMB Control Number:</E>
                     1219-0148.
                </P>
                <P>
                    <E T="03">Affected Public:</E>
                     Businesses or other for-profits.
                </P>
                <P>
                    <E T="03">Number of Respondents:</E>
                     168.
                </P>
                <P>
                    <E T="03">Frequency:</E>
                     Annually.
                </P>
                <P>
                    <E T="03">Number of Responses:</E>
                     245,337.
                </P>
                <P>
                    <E T="03">Annual Burden Hours:</E>
                     697 hours.
                </P>
                <P>
                    <E T="03">Total Estimated Annual Other Costs Burden:</E>
                     $0.
                </P>
                <EXTRACT>
                    <FP>(Authority: 44 U.S.C. 3507(a)(1)(D))</FP>
                </EXTRACT>
                <SIG>
                    <NAME>Michael Howell,</NAME>
                    <TITLE>Senior Paperwork Reduction Act Analyst.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10425 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4510-43-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF LABOR</AGENCY>
                <SUBJECT>Agency Information Collection Activities; Submission for OMB Review; Comment Request; Registration and Equal Employment Opportunity in Apprenticeship Programs</SUBJECT>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of availability; request for comments.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Department of Labor (DOL) is submitting this Employment and Training Administration (ETA)-sponsored information collection request (ICR) to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995 (PRA). Public comments on the ICR are invited.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The OMB will consider all written comments that the agency receives on or before June 13, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Written comments and recommendations for the proposed information collection should be sent within 30 days of publication of this notice to 
                        <E T="03">www.reginfo.gov/public/do/PRAMain.</E>
                         Find this particular information collection by selecting “Currently under 30-day Review—Open for Public Comments” or by using the search function.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Michael Howell by telephone at 202-693-6782, or by email at 
                        <E T="03">DOL_PRA_PUBLIC@dol.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    Title 29 CFR 29 sets forth labor standards to safeguard the welfare of apprentices and to extend the application of such standards by prescribing policies and procedures concerning registration of apprenticeship. This information collection, ETA 671, has two sections: the first records the sponsor's information and the second is for the apprentice's information, filled out by the sponsor based on employment records. The submission is reviewed and signed by the state agency/Office of Apprenticeship. The information is collected on a one-time basis. For additional substantive information about this ICR, see the related notice published in the 
                    <E T="04">Federal Register</E>
                     on December 8, 2023 (88 FR 85654).
                </P>
                <P>
                    Comments are invited on: (1) whether the collection of information is 
                    <PRTPAGE P="41996"/>
                    necessary for the proper performance of the functions of the Department, including whether the information will have practical utility; (2) the accuracy of the agency's estimates of the burden and cost of the collection of information, including the validity of the methodology and assumptions used; (3) ways to enhance the quality, utility and clarity of the information collection; and (4) ways to minimize the burden of the collection of information on those who are to respond, including the use of automated collection techniques or other forms of information technology.
                </P>
                <P>
                    This information collection is subject to the PRA. A Federal agency generally cannot conduct or sponsor a collection of information, and the public is generally not required to respond to an information collection, unless the OMB approves it and displays a currently valid OMB Control Number. In addition, notwithstanding any other provisions of law, no person shall generally be subject to penalty for failing to comply with a collection of information that does not display a valid OMB Control Number. 
                    <E T="03">See</E>
                     5 CFR 1320.5(a) and 1320.6.
                </P>
                <P>DOL seeks PRA authorization for this information collection for three (3) years. OMB authorization for an ICR cannot be for more than three (3) years without renewal. The DOL notes that information collection requirements submitted to the OMB for existing ICRs receive a month-to-month extension while they undergo review.</P>
                <P>
                    <E T="03">Agency:</E>
                     DOL-ETA.
                </P>
                <P>
                    <E T="03">Title of Collection:</E>
                     Registration and Equal Employment Opportunity in Apprenticeship Programs.
                </P>
                <P>
                    <E T="03">OMB Control Number:</E>
                     1205-0223.
                </P>
                <P>
                    <E T="03">Affected Public:</E>
                     Individuals/households, state/local/tribal governments, Federal government, private sector (businesses or other for-profits, and, not-for-profit institutions).
                </P>
                <P>
                    <E T="03">Total Estimated Number of Respondents:</E>
                     704,577.
                </P>
                <P>
                    <E T="03">Total Estimated Number of Responses:</E>
                     1,066,917.
                </P>
                <P>
                    <E T="03">Total Estimated Annual Time Burden:</E>
                     522,653 hours.
                </P>
                <P>
                    <E T="03">Total Estimated Annual Other Costs Burden:</E>
                     $0.
                </P>
                <EXTRACT>
                    <FP>(Authority: 44 U.S.C. 3507(a)(1)(D))</FP>
                </EXTRACT>
                <SIG>
                    <NAME>Michael Howell,</NAME>
                    <TITLE>Senior Paperwork Reduction Act Analyst.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10427 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4510-FN-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">NATIONAL TRANSPORTATION SAFETY BOARD</AGENCY>
                <SUBJECT>Sunshine Act Meetings</SUBJECT>
                <PREAMHD>
                    <HD SOURCE="HED">TIME AND DATE:</HD>
                    <P>9:30 a.m. EDT, Thursday June 6, 2024.</P>
                </PREAMHD>
                <PREAMHD>
                    <HD SOURCE="HED">PLACE:</HD>
                    <P>NTSB Conference Center, 429 L'Enfant Plaza SW, Washington, DC 20594.</P>
                </PREAMHD>
                <PREAMHD>
                    <HD SOURCE="HED">STATUS:</HD>
                    <P>The one item is open to the public.</P>
                </PREAMHD>
                <PREAMHD>
                    <HD SOURCE="HED">MATTERS TO BE CONSIDERED:</HD>
                    <P/>
                </PREAMHD>
                <FP SOURCE="FP-1">71107 Aviation Investigative Report—Runway Incursion and Overflight, Southwest Airlines Flight 708, Boeing 737-700, N7827A, and Federal Express Flight 1432, Boeing 767-300, N297FE, Austin, Texas, February 4, 2023.</FP>
                <PREAMHD>
                    <HD SOURCE="HED">CONTACT PERSON FOR MORE INFORMATION:</HD>
                    <P>
                        Candi Bing at (202) 590-8384 or by email at 
                        <E T="03">bingc@ntsb.gov.</E>
                    </P>
                    <P>
                        <E T="03">Media Information Contact:</E>
                         Peter Knudson by email at 
                        <E T="03">peter.knudson@ntsb.gov</E>
                         (202) 314-6100.
                    </P>
                    <P>
                        Individuals requesting specific accommodations should contact Rochelle McCallister at (202) 314-6305 or by email at 
                        <E T="03">Rochelle.McCallister@ntsb.gov</E>
                         by Wednesday, May 30, 2024.
                    </P>
                    <P>
                        The public may view it through a live or archived webcast by accessing a link under “Upcoming Events” on the NTSB home page at 
                        <E T="03">www.ntsb.gov.</E>
                    </P>
                    <P>
                        Schedule updates, including weather-related cancellations, are also available at 
                        <E T="03">www.ntsb.gov.</E>
                    </P>
                    <P>The National Transportation Safety Board is holding this meeting under the Government in the Sunshine Act, 5 U.S.C. 552(b).</P>
                </PREAMHD>
                <SIG>
                    <DATED> Dated: Friday, May 10, 2024.</DATED>
                    <NAME>LaSean R. McCray,</NAME>
                    <TITLE>Assistant Federal Register Liaison Officer.</TITLE>
                </SIG>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10619 Filed 5-10-24; 11:15 am]</FRDOC>
            <BILCOD>BILLING CODE 7533-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">NUCLEAR REGULATORY COMMISSION</AGENCY>
                <DEPDOC>[NRC-2024-0087]</DEPDOC>
                <SUBJECT>Monthly Notice; Applications and Amendments to Facility Operating Licenses and Combined Licenses Involving No Significant Hazards Considerations</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Nuclear Regulatory Commission.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Monthly notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>Pursuant to section 189a.(2) of the Atomic Energy Act of 1954, as amended (the Act), the U.S. Nuclear Regulatory Commission (NRC) is publishing this regular monthly notice. The Act requires the Commission to publish notice of any amendments issued, or proposed to be issued, and grants the Commission the authority to issue and make immediately effective any amendment to an operating license or combined license, as applicable, upon a determination by the Commission that such amendment involves no significant hazards consideration (NSHC), notwithstanding the pendency before the Commission of a request for a hearing from any person.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Comments must be filed by June 13, 2024. A request for a hearing or petitions for leave to intervene must be filed by July 15, 2024. This monthly notice includes all amendments issued, or proposed to be issued, from March 29, 2024, to April 25, 2024. The last monthly notice was published on April 16, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>You may submit comments by any of the following methods; however, the NRC encourages electronic comment submission through the Federal rulemaking website.</P>
                    <P>
                        • 
                        <E T="03">Federal rulemaking website:</E>
                         Go to 
                        <E T="03">https://www.regulations.gov</E>
                         and search for Docket ID NRC-2024-0087. Address questions about Docket IDs in 
                        <E T="03">Regulations.gov</E>
                         to Stacy Schumann; telephone: 301-415-0624; email: 
                        <E T="03">Stacy.Schumann@nrc.gov</E>
                        . For technical questions, contact the individual listed in the 
                        <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                         section of this document.
                    </P>
                    <P>
                        • 
                        <E T="03">Mail comments to:</E>
                         Office of Administration, Mail Stop: TWFN-7-A60M, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, ATTN: Program Management, Announcements and Editing Staff.
                    </P>
                    <P>
                        For additional direction on obtaining information and submitting comments, see “Obtaining Information and Submitting Comments” in the 
                        <E T="02">SUPPLEMENTARY INFORMATION</E>
                         section of this document.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Angela Baxter, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, telephone: 301-415-8209; email: 
                        <E T="03">Angela.Baxter@nrc.gov</E>
                        .
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P/>
                <HD SOURCE="HD1">I. Obtaining Information and Submitting Comments</HD>
                <HD SOURCE="HD2">A. Obtaining Information</HD>
                <P>
                    Please refer to Docket ID NRC-2024-0087, facility name, unit number(s), docket number(s), application date, and subject when contacting the NRC about the availability of information for this action. You may obtain publicly 
                    <PRTPAGE P="41997"/>
                    available information related to this action by any of the following methods:
                </P>
                <P>
                    • 
                    <E T="03">Federal Rulemaking Website:</E>
                     Go to 
                    <E T="03">https://www.regulations.gov</E>
                     and search for Docket ID NRC-2024-0087.
                </P>
                <P>
                    • 
                    <E T="03">NRC's Agencywide Documents Access and Management System (ADAMS):</E>
                     You may obtain publicly available documents online in the ADAMS Public Documents collection at 
                    <E T="03">https://www.nrc.gov/reading-rm/adams.html</E>
                    . To begin the search, select “Begin Web-based ADAMS Search.” For problems with ADAMS, please contact the NRC's Public Document Room (PDR) reference staff at 1-800-397-4209, at 301-415-4737, or by email to 
                    <E T="03">PDR.Resource@nrc.gov</E>
                    . The ADAMS accession number for each document referenced (if it is available in ADAMS) is provided the first time that it is mentioned in this document.
                </P>
                <P>
                    • 
                    <E T="03">NRC's PDR:</E>
                     The PDR, where you may examine and order copies of publicly available documents, is open by appointment. To make an appointment to visit the PDR, please send an email to 
                    <E T="03">PDR.Resource@nrc.gov</E>
                     or call 1-800-397-4209 or 301-415-4737, between 8 a.m. and 4 p.m. eastern time (ET), Monday through Friday, except Federal holidays.
                </P>
                <HD SOURCE="HD2">B. Submitting Comments</HD>
                <P>
                    The NRC encourages electronic comment submission through the Federal rulemaking website (
                    <E T="03">https://www.regulations.gov</E>
                    ). Please include Docket ID NRC-2024-0087, facility name, unit number(s), docket number(s), application date, and subject, in your comment submission.
                </P>
                <P>
                    The NRC cautions you not to include identifying or contact information that you do not want to be publicly disclosed in your comment submission. The NRC will post all comment submissions at 
                    <E T="03">https://www.regulations.gov</E>
                     as well as enter the comment submissions into ADAMS. The NRC does not routinely edit comment submissions to remove identifying or contact information.
                </P>
                <P>If you are requesting or aggregating comments from other persons for submission to the NRC, then you should inform those persons not to include identifying or contact information that they do not want to be publicly disclosed in their comment submission. Your request should state that the NRC does not routinely edit comment submissions to remove such information before making the comment submissions available to the public or entering the comment into ADAMS.</P>
                <HD SOURCE="HD1">II. Notice of Consideration of Issuance of Amendments to Facility Operating Licenses and Combined Licenses and Proposed No Significant Hazards Consideration Determination</HD>
                <P>
                    For the facility-specific amendment requests shown in this notice, the Commission finds that the licensees' analyses provided, consistent with section 50.91 of title 10 of 
                    <E T="03">the Code of Federal Regulations</E>
                     (10 CFR) “Notice for public comment; State consultation,” are sufficient to support the proposed determinations that these amendment requests involve NSHC. Under the Commission's regulations in 10 CFR 50.92, operation of the facilities in accordance with the proposed amendments would not (1) involve a significant increase in the probability or consequences of an accident previously evaluated; or (2) create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) involve a significant reduction in a margin of safety.
                </P>
                <P>The Commission is seeking public comments on these proposed determinations. Any comments received within 30 days after the date of publication of this notice will be considered in making any final determinations.</P>
                <P>
                    Normally, the Commission will not issue the amendments until the expiration of 60 days after the date of publication of this notice. The Commission may issue any of these license amendments before expiration of the 60-day period provided that its final determination is that the amendment involves NSHC. In addition, the Commission may issue any of these amendments prior to the expiration of the 30-day comment period if circumstances change during the 30-day comment period such that failure to act in a timely way would result, for example in derating or shutdown of the facility. If the Commission takes action on any of these amendments prior to the expiration of either the comment period or the notice period, it will publish in the 
                    <E T="04">Federal Register</E>
                     a notice of issuance. If the Commission makes a final NSHC determination for any of these amendments, any hearing will take place after issuance. The Commission expects that the need to take action on any amendment before 60 days have elapsed will occur very infrequently.
                </P>
                <HD SOURCE="HD2">A. Opportunity To Request a Hearing and Petition for Leave To Intervene</HD>
                <P>Within 60 days after the date of publication of this notice, any person (petitioner) whose interest may be affected by any of these actions may file a request for a hearing and petition for leave to intervene (petition) with respect to that action. Petitions shall be filed in accordance with the Commission's “Agency Rules of Practice and Procedure” in 10 CFR part 2. Interested persons should consult a current copy of 10 CFR 2.309. If a petition is filed, the Commission or a presiding officer will rule on the petition and, if appropriate, a notice of a hearing will be issued.</P>
                <P>Petitions must be filed no later than 60 days from the date of publication of this notice in accordance with the filing instructions in the “Electronic Submissions (E-Filing)” section of this document. Petitions and motions for leave to file new or amended contentions that are filed after the deadline will not be entertained absent a determination by the presiding officer that the filing demonstrates good cause by satisfying the three factors in 10 CFR 2.309(c)(1)(i) through (iii).</P>
                <P>If a hearing is requested, and the Commission has not made a final determination on the issue of no significant hazards consideration, the Commission will make a final determination on the issue of no significant hazards consideration, which will serve to establish when the hearing is held. If the final determination is that the amendment request involves no significant hazards consideration, the Commission may issue the amendment and make it immediately effective, notwithstanding the request for a hearing. Any hearing would take place after issuance of the amendment. If the final determination is that the amendment request involves a significant hazards consideration, then any hearing held would take place before the issuance of the amendment unless the Commission finds an imminent danger to the health or safety of the public, in which case it will issue an appropriate order or rule under 10 CFR part 2.</P>
                <P>A State, local governmental body, Federally recognized Indian Tribe, or designated agency thereof, may submit a petition to the Commission to participate as a party under 10 CFR 2.309(h) no later than 60 days from the date of publication of this notice. Alternatively, a State, local governmental body, Federally recognized Indian Tribe, or agency thereof may participate as a non-party under 10 CFR 2.315(c).</P>
                <PRTPAGE P="41998"/>
                <P>
                    For information about filing a petition and about participation by a person not a party under 10 CFR 2.315, see ADAMS Accession No. ML20340A053 (
                    <E T="03">https://adamswebsearch2.nrc.gov/webSearch2/main.jsp?AccessionNumber=ML20340A053</E>
                    ) and on the NRC's public website at 
                    <E T="03">https://www.nrc.gov/about-nrc/regulatory/adjudicatory/hearing.html#participate</E>
                    .
                </P>
                <HD SOURCE="HD2">B. Electronic Submissions (E-Filing)</HD>
                <P>
                    All documents filed in NRC adjudicatory proceedings, including documents filed by an interested State, local governmental body, Federally recognized Indian Tribe, or designated agency thereof that requests to participate under 10 CFR 2.315(c), must be filed in accordance with 10 CFR 2.302. The E-Filing process requires participants to submit and serve all adjudicatory documents over the internet, or in some cases, to mail copies on electronic storage media, unless an exemption permitting an alternative filing method, as further discussed, is granted. Detailed guidance on electronic submissions is located in the “Guidance for Electronic Submissions to the NRC” (ADAMS Accession No. ML13031A056) and on the NRC's public website at 
                    <E T="03">https://www.nrc.gov/site-help/e-submittals.html</E>
                    .
                </P>
                <P>
                    To comply with the procedural requirements of E-Filing, at least 10 days prior to the filing deadline, the participant should contact the Office of the Secretary by email at 
                    <E T="03">Hearing.Docket@nrc.gov,</E>
                     or by telephone at 301-415-1677, to (1) request a digital identification (ID) certificate, which allows the participant (or its counsel or representative) to digitally sign submissions and access the E-Filing system for any proceeding in which it is participating; and (2) advise the Secretary that the participant will be submitting a petition or other adjudicatory document (even in instances in which the participant, or its counsel or representative, already holds an NRC-issued digital ID certificate). Based upon this information, the Secretary will establish an electronic docket for the proceeding if the Secretary has not already established an electronic docket.
                </P>
                <P>
                    Information about applying for a digital ID certificate is available on the NRC's public website at 
                    <E T="03">https://www.nrc.gov/site-help/e-submittals/getting-started.html</E>
                    . After a digital ID certificate is obtained and a docket created, the participant must submit adjudicatory documents in Portable Document Format. Guidance on submissions is available on the NRC's public website at 
                    <E T="03">https://www.nrc.gov/site-help/electronic-sub-ref-mat.html</E>
                    . A filing is considered complete at the time the document is submitted through the NRC's E-Filing system. To be timely, an electronic filing must be submitted to the E-Filing system no later than 11:59 p.m. ET on the due date. Upon receipt of a transmission, the E-Filing system time-stamps the document and sends the submitter an email confirming receipt of the document. The E-Filing system also distributes an email that provides access to the document to the NRC's Office of the General Counsel and any others who have advised the Office of the Secretary that they wish to participate in the proceeding, so that the filer need not serve the document on those participants separately. Therefore, applicants and other participants (or their counsel or representative) must apply for and receive a digital ID certificate before adjudicatory documents are filed to obtain access to the documents via the E-Filing system.
                </P>
                <P>
                    A person filing electronically using the NRC's adjudicatory E-Filing system may seek assistance by contacting the NRC's Electronic Filing Help Desk through the “Contact Us” link located on the NRC's public website at 
                    <E T="03">https://www.nrc.gov/site-help/e-submittals.html</E>
                    , by email to 
                    <E T="03">MSHD.Resource@nrc.gov,</E>
                     or by a toll-free call at 1-866-672-7640. The NRC Electronic Filing Help Desk is available between 9 a.m. and 6 p.m., ET, Monday through Friday, except Federal holidays.
                </P>
                <P>Participants who believe that they have good cause for not submitting documents electronically must file an exemption request, in accordance with 10 CFR 2.302(g), with their initial paper filing stating why there is good cause for not filing electronically and requesting authorization to continue to submit documents in paper format. Such filings must be submitted in accordance with 10 CFR 2.302(b)-(d). Participants filing adjudicatory documents in this manner are responsible for serving their documents on all other participants. Participants granted an exemption under 10 CFR 2.302(g)(2) must still meet the electronic formatting requirement in 10 CFR 2.302(g)(1), unless the participant also seeks and is granted an exemption from 10 CFR 2.302(g)(1).</P>
                <P>
                    Documents submitted in adjudicatory proceedings will appear in the NRC's electronic hearing docket, which is publicly available at 
                    <E T="03">https://adams.nrc.gov/ehd,</E>
                     unless excluded pursuant to an order of the presiding officer. If you do not have an NRC-issued digital ID certificate as previously described, click “cancel” when the link requests certificates and you will be automatically directed to the NRC's electronic hearing dockets where you will be able to access any publicly available documents in a particular hearing docket. Participants are requested not to include personal privacy information such as social security numbers, home addresses, or personal phone numbers in their filings unless an NRC regulation or other law requires submission of such information. With respect to copyrighted works, except for limited excerpts that serve the purpose of the adjudicatory filings and would constitute a Fair Use application, participants should not include copyrighted materials in their submission.
                </P>
                <P>The following table provides the plant name, docket number, date of application, ADAMS accession number, and location in the application of the licensees' proposed NSHC determinations. For further details with respect to these license amendment applications, see the applications for amendment, which are available for public inspection in ADAMS. For additional direction on accessing information related to this document, see the “Obtaining Information and Submitting Comments” section of this document.</P>
                <GPOTABLE COLS="2" OPTS="L2,nj,p1,8/9,i1" CDEF="s100,r100">
                    <TTITLE>License Amendment Requests</TTITLE>
                    <BOXHD>
                        <CHED H="1"> </CHED>
                        <CHED H="1"> </CHED>
                    </BOXHD>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">Arizona Public Service Company, et al; Palo Verde Nuclear Generating Station, Units 1, 2, and 3; Maricopa County, AZ</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket Nos</ENT>
                        <ENT>50-528, 50-529, 50-530.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Application date</ENT>
                        <ENT>March 8, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession No</ENT>
                        <ENT>ML24068A252.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Location in Application of NSHC</ENT>
                        <ENT>Pages 13-16 of the Enclosure.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendments</ENT>
                        <ENT>The proposed amendments would revise Technical Specification (TS) 3.5.1, “Safety Injection Tanks (SITs)—Operating,” and TS 3.5.2, SITs—Shutdown,” using risk-informed process for evaluations.</ENT>
                    </ROW>
                    <ROW>
                        <PRTPAGE P="41999"/>
                        <ENT I="01">Proposed Determination</ENT>
                        <ENT>NSHC.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Name of Attorney for Licensee, Mailing Address</ENT>
                        <ENT>Carey Fleming, Senior Counsel, Pinnacle West Capital Corporation, 500 N 5th Street, MS 8695, Phoenix, AZ 85004.</ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">NRC Project Manager, Telephone Number</ENT>
                        <ENT>William Orders, 301-415-3329.</ENT>
                    </ROW>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">DTE Electric Company; Fermi, Unit 2; Monroe County, MI</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket No</ENT>
                        <ENT>50-341.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Application date</ENT>
                        <ENT>March 21, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession No</ENT>
                        <ENT>ML24081A326.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Location in Application of NSHC</ENT>
                        <ENT>Pages 5-8 of Attachment 1.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendment</ENT>
                        <ENT>The proposed amendment requests adoption of Technical Specification Task Force (TSTF) Travelers, TSTF-505, Revision 2, “Provide Risk-Informed Extended Completion Times—RITSTF [Risk Informed TSTF] Initiative 4b,” TSTF-439, Revision 2, “Eliminate Second Completion Times Limiting Time From Discovery of Failure to Meet an LCO [limiting condition for operation],” and TSTF-591, Revision 0, “Revise Risk Informed Completion Time (RICT) Program.”</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Proposed Determination</ENT>
                        <ENT>NSHC.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Name of Attorney for Licensee, Mailing Address</ENT>
                        <ENT>Jon P. Christinidis, DTE Electric Company, Expert Attorney—Regulatory, 1635 WCB, One Energy Plaza, Detroit, MI 48226.</ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">NRC Project Manager, Telephone Number</ENT>
                        <ENT>Surinder Arora, 301-415-1421.</ENT>
                    </ROW>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">Indiana Michigan Power Company; Donald C. Cook Nuclear Plant, Units 1 and 2; Berrien County, MI</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket Nos</ENT>
                        <ENT>50-315, 50-316.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Application date</ENT>
                        <ENT>March 6, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession No</ENT>
                        <ENT>ML24073A234.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Location in Application of NSHC</ENT>
                        <ENT>Pages 18-20 of Enclosure 2.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendments</ENT>
                        <ENT>
                            The proposed amendments would modify the Donald C. Cook Nuclear Plant, Units 1 and 2, licensing basis, by the addition of a license condition, to allow for the implementation of the provisions of 10 CFR 50.69, “Risk-Informed Categorization and Treatment of Structures, Systems and Components for Nuclear Power Reactors.” The provisions of 10 CFR 50.69 allow adjustment of the scope of equipment subject to special treatment controls (
                            <E T="03">e.g.,</E>
                             quality assurance, testing, inspection, condition monitoring, assessment, and evaluation).
                        </ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Proposed Determination</ENT>
                        <ENT>NSHC.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Name of Attorney for Licensee, Mailing Address</ENT>
                        <ENT>Robert B. Haemer, Senior Nuclear Counsel, Indiana Michigan Power Company, One Cook Place, Bridgman, MI 49106.</ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">NRC Project Manager, Telephone Number</ENT>
                        <ENT>Scott Wall, 301-415-2855.</ENT>
                    </ROW>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">Pacific Gas and Electric Company; Diablo Canyon Power Plant, Units 1 and 2; San Luis Obispo County, CA</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket Nos</ENT>
                        <ENT>50-275, 50-323.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Application date</ENT>
                        <ENT>February 28, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession No</ENT>
                        <ENT>ML24059A448.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Location in Application of NSHC</ENT>
                        <ENT>Pages 7-9 of the Enclosure.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendments</ENT>
                        <ENT>The proposed amendments would revise Technical Specification 5.6.6, “Reactor Coolant System (RCS) Pressure and Temperature Limits Report (PTLR),” regarding the fluence calculational methodology used to determine the pressure and temperature limits.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Proposed Determination</ENT>
                        <ENT>NSHC.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Name of Attorney for Licensee, Mailing Address</ENT>
                        <ENT>Jennifer Post, Esq., Pacific Gas and Electric Co., 77 Beale Street, Room 3065, Mail Code B30A, San Francisco, CA 94105.</ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">NRC Project Manager, Telephone Number</ENT>
                        <ENT>Samson Lee, 301-415-3168.</ENT>
                    </ROW>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">Southern Nuclear Operating Company, Inc.; Joseph M. Farley Nuclear Plant, Units 1 and 2; Houston County, AL</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket Nos</ENT>
                        <ENT>50-348, 50-364.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Application date</ENT>
                        <ENT>April 5, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession No</ENT>
                        <ENT>ML24096B775.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Location in Application of NSHC</ENT>
                        <ENT>Pages E-5 through E-7 of the Enclosure.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendments</ENT>
                        <ENT>The proposed amendments would revise the Joseph M. Farley Nuclear Plant, Units 1 and 2, Technical Specification 3.6.6, “Containment Spray and Cooling Systems,” to revise the frequency of Surveillance Requirement 3.6.6.8.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Proposed Determination</ENT>
                        <ENT>NSHC.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Name of Attorney for Licensee, Mailing Address</ENT>
                        <ENT>Millicent Ronnlund, Vice President and General Counsel, Southern Nuclear Operating Co., Inc., P.O. Box 1295, Birmingham, AL 35201-1295.</ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">NRC Project Manager, Telephone Number</ENT>
                        <ENT>Zachary Turner, 301-415-6303.</ENT>
                    </ROW>
                    <ROW EXPSTB="01" RUL="s">
                        <PRTPAGE P="42000"/>
                        <ENT I="21">
                            <E T="02">Southern Nuclear Operating Company, Inc.; Vogtle Electric Generating Plant, Units 1 and 2; Burke County, GA</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket Nos</ENT>
                        <ENT>50-424, 50-425.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Application date</ENT>
                        <ENT>March 20, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession No</ENT>
                        <ENT>ML24080A455.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Location in Application of NSHC</ENT>
                        <ENT>Pages E-12 and E-13 of the Enclosure.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendments</ENT>
                        <ENT>The proposed amendments would revise emergency diesel generator frequency and voltage ranges for Technical Specification 3.8.1, “AC [Alternating Current] Sources—Operating,” Surveillance Requirements.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Proposed Determination</ENT>
                        <ENT>NSHC.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Name of Attorney for Licensee, Mailing Address</ENT>
                        <ENT>Millicent Ronnlund, Vice President and General Counsel, Southern Nuclear Operating Co., Inc., P.O. Box 1295, Birmingham, AL 35201-1295.</ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">NRC Project Manager, Telephone Number</ENT>
                        <ENT>John Lamb, 301-415-3100.</ENT>
                    </ROW>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">Tennessee Valley Authority; Sequoyah Nuclear Plant, Units 1 and 2; Hamilton County, TN</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket Nos</ENT>
                        <ENT>50-327, 50-328.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Application date</ENT>
                        <ENT>April 15, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession No</ENT>
                        <ENT>ML24106A057.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Location in Application of NSHC</ENT>
                        <ENT>Pages E7 and E8 of the Enclosure.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendments</ENT>
                        <ENT>The proposed amendments would revise the Sequoyah Nuclear Plant, Units 1 and 2, Technical Specification (TS) 3.8.1, “AC [alternating current] Sources—Operating,” to delete Surveillance Requirement (SR) 3.8.1.8, and would revise TS 3.8.2, “AC Sources—Shutdown,” to delete the reference to SR 3.8.1.8.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Proposed Determination</ENT>
                        <ENT>NSHC.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Name of Attorney for Licensee, Mailing Address</ENT>
                        <ENT>David Fountain, Executive VP and General Counsel, Tennessee Valley Authority, 6A West Tower, 400 West Summit Hill Drive, Knoxville, TN 37902.</ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">NRC Project Manager, Telephone Number</ENT>
                        <ENT>Perry Buckberg, 301-415-1383.</ENT>
                    </ROW>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">Vallecitos Boiling Water Reactor, Alameda County, CA</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket No</ENT>
                        <ENT>50-18.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Application dates</ENT>
                        <ENT>September 7, 2023, as supplemented by letters dated September 15, 2023, October 31, 2023, and March 25, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession Nos</ENT>
                        <ENT>ML23250A267, ML23261A591 (package), ML23304A300, ML24085A792.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Location in Application of NSHC</ENT>
                        <ENT>Pages 1-2 of Enclosure 1 to the supplement dated March 25, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendment</ENT>
                        <ENT>The proposed amendment would approve the license termination plan which implements the licensing decommissioning strategy that is outlined in the limited post-shutdown decommissioning activities report.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Proposed Determination</ENT>
                        <ENT>NSHC.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Name of Attorney(s) for Licensee, Mailing Address</ENT>
                        <ENT>Angela Thornhill, General Counsel, GE-Hitachi Nuclear Energy Americas LLC, 3901 Castle Hayne Road, Wilmington, NC 28402; and Gregory Di Carlo, Vice President/General Counsel, NorthStar Group Services, Inc., 15760 West Power Street, NA1A, Crystal River, FL 34428.</ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">NRC Project Manager, Telephone Number</ENT>
                        <ENT>Jack Parrott, 301-415-6634.</ENT>
                    </ROW>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">Vistra Operations Company LLC; Comanche Peak Nuclear Power Plant, Unit Nos. 1 and 2; Somervell County, TX</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket Nos</ENT>
                        <ENT>50-445, 50-446.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Application dates</ENT>
                        <ENT>February 28, 2024, as supplemented by letter dated April 1, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession Nos</ENT>
                        <ENT>ML24059A390, ML24092A236.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Location in Application of NSHC</ENT>
                        <ENT>Pages 1-3 of the Enclosure.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendments</ENT>
                        <ENT>The proposed amendments would revise technical specifications to adopt Technical Specification Task Force (TSTF) Traveler TSTF-591, “Revise Risk-Informed Completion Time (RICT) Program.”</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Proposed Determination</ENT>
                        <ENT>NSHC.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Name of Attorney for Licensee, Mailing Address</ENT>
                        <ENT>Timothy P. Matthews, Esq., Morgan, Lewis and Bockius, 1111 Pennsylvania Avenue NW, Washington, DC 20004.</ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">NRC Project Manager, Telephone Number</ENT>
                        <ENT>Samson Lee, 301-415-3168.</ENT>
                    </ROW>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">Vistra Operations Company LLC; Comanche Peak Nuclear Power Plant, Unit Nos. 1 and 2; Somervell County, TX</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket Nos</ENT>
                        <ENT>50-445, 50-446.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Application date</ENT>
                        <ENT>February 28, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession No</ENT>
                        <ENT>ML24059A386.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Location in Application of NSHC</ENT>
                        <ENT>Pages 2-3 of Enclosure.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendments</ENT>
                        <ENT>The proposed amendments would revise technical specifications to adopt Technical Specification Task Force (TSTF) Traveler TSTF-589, “Eliminate Automatic Diesel Generator Start During Shutdown.”</ENT>
                    </ROW>
                    <ROW>
                        <PRTPAGE P="42001"/>
                        <ENT I="01">Proposed Determination</ENT>
                        <ENT>NSHC.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Name of Attorney for Licensee, Mailing Address</ENT>
                        <ENT>Timothy P. Matthews, Esq., Morgan, Lewis and Bockius, 1111 Pennsylvania Avenue NW, Washington, DC 20004.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">NRC Project Manager, Telephone Number</ENT>
                        <ENT>Samson Lee, 301-415-3168.</ENT>
                    </ROW>
                </GPOTABLE>
                <HD SOURCE="HD1">III. Notice of Issuance of Amendments to Facility Operating Licenses and Combined Licenses</HD>
                <P>During the period since publication of the last monthly notice, the Commission has issued the following amendments. The Commission has determined for each of these amendments that the application complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations. The Commission has made appropriate findings as required by the Act and the Commission's rules and regulations in 10 CFR chapter I, which are set forth in the license amendment.</P>
                <P>
                    A notice of consideration of issuance of amendment to facility operating license or combined license, as applicable, proposed NSHC determination, and opportunity for a hearing in connection with these actions, were published in the 
                    <E T="04">Federal Register</E>
                     as indicated in the safety evaluation for each amendment.
                </P>
                <P>Unless otherwise indicated, the Commission has determined that these amendments satisfy the criteria for categorical exclusion in accordance with 10 CFR 51.22. Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared for these amendments. If the Commission has prepared an environmental assessment under the special circumstances provision in 10 CFR 51.22(b) and has made a determination based on that assessment, it is so indicated in the safety evaluation for the amendment.</P>
                <P>
                    For further details with respect to each action, see the amendment and associated documents such as the Commission's letter and safety evaluation, which may be obtained using the ADAMS accession numbers indicated in the following table. The safety evaluation will provide the ADAMS accession numbers for the application for amendment and the 
                    <E T="04">Federal Register</E>
                     citation for any environmental assessment. All of these items can be accessed as described in the “Obtaining Information and Submitting Comments” section of this document.
                </P>
                <GPOTABLE COLS="2" OPTS="L2,nj,p1,8/9,i1" CDEF="s100,r100">
                    <TTITLE>License Amendment Issuance(s)</TTITLE>
                    <BOXHD>
                        <CHED H="1"> </CHED>
                        <CHED H="1"> </CHED>
                    </BOXHD>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">Constellation FitzPatrick, LLC and Constellation Energy Generation, LLC; James A. FitzPatrick Nuclear Power Plant; Oswego County, NY</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket No</ENT>
                        <ENT>50-333.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Amendment Date</ENT>
                        <ENT>March 28, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession No</ENT>
                        <ENT>ML24068A053.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Amendment No</ENT>
                        <ENT>354.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendment</ENT>
                        <ENT>The amendment modified Surveillance Requirement (SR) 3.3.1.2.4 to incorporate an additional acceptance criterion based on a higher signal to noise ratio as provided in General Electric Service Information Letter 478 dated December 16, 1988. Specifically, an “or” statement was added to SR 3.3.1.2.4 as follows: “or Verify count rate is ≥0.7 [counts per second] cps with a signal to noise ratio ≥20:1.”</ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">Public Comments Received as to Proposed NSHC (Yes/No)</ENT>
                        <ENT>No.</ENT>
                    </ROW>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">Duke Energy Carolinas, LLC; McGuire Nuclear Station, Units 1 and 2; Mecklenburg County, NC</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket Nos</ENT>
                        <ENT>50-369, 50-370.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Amendment Date</ENT>
                        <ENT>April 8, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession No</ENT>
                        <ENT>ML24052A306.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Amendment Nos</ENT>
                        <ENT>331 (Unit 1) and 310 (Unit 2).</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendments</ENT>
                        <ENT>The amendments modified the licensing basis for the implementation of the provisions of 10 CFR 50.69, “Risk-informed categorization and treatment of structures, systems and components for nuclear power reactors,” which would allow adjustment of the scope of equipment subject to special treatment controls.</ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">Public Comments Received as to Proposed NSHC (Yes/No)</ENT>
                        <ENT>No.</ENT>
                    </ROW>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">Southern Nuclear Operating Company, Inc.; Edwin I. Hatch Nuclear Plant, Units 1 and 2; Appling County, GA</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket Nos</ENT>
                        <ENT>50-321, 50-366.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Amendment Date</ENT>
                        <ENT>April 24, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession No</ENT>
                        <ENT>ML23032A332.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Amendment Nos</ENT>
                        <ENT>322 (Unit 1) and 267 (Unit 2).</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendments</ENT>
                        <ENT>The amendments revised the renewed facility operating licenses and technical specifications Table 1.1-1, “MODES,” for Edwin I. Hatch Nuclear Plant, Units 1 and 2, to relax the required number of fully tensioned reactor pressure vessel head closure bolts.</ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">Public Comments Received as to Proposed NSHC (Yes/No)</ENT>
                        <ENT>No.</ENT>
                    </ROW>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">Southern Nuclear Operating Company, Inc.; Vogtle Electric Generating Plant, Units 1 and 2; Burke County, GA</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket Nos</ENT>
                        <ENT>50-424, 50-425.</ENT>
                    </ROW>
                    <ROW>
                        <PRTPAGE P="42002"/>
                        <ENT I="01">Amendment Date</ENT>
                        <ENT>April 10, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession No</ENT>
                        <ENT>ML24030A909.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Amendment Nos</ENT>
                        <ENT>224 (Unit 1) and 207 (Unit 2).</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendments</ENT>
                        <ENT>The amendments revised Technical Specification (TS) 3.4.14, “RCS [Reactor Coolant System] Pressure Isolation Valve (PIV) Leakage,” Surveillance Requirement 3.4.14.1 to limit required testing to frequencies specified in the Inservice Testing Program in accordance with the American Society of Mechanical Engineers Code for Operation and Maintenance of Nuclear Power Plants by removing all other SR 3.4.14.1 frequency testing criteria from the current TSs.</ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">Public Comments Received as to Proposed NSHC (Yes/No)</ENT>
                        <ENT>No.</ENT>
                    </ROW>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">Susquehanna Nuclear, LLC and Allegheny Electric Cooperative, Inc.; Susquehanna Steam Electric Station, Units 1 and 2; Luzerne County, PA</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket Nos</ENT>
                        <ENT>50-387, 50-388.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Amendment Date</ENT>
                        <ENT>April 22, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession No</ENT>
                        <ENT>ML24082A137.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Amendment Nos</ENT>
                        <ENT>287 (Unit 1) and 271 (Unit 2).</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendments</ENT>
                        <ENT>The amendments revised the technical specifications to adopt the Technical Specifications Task Force (TSTF) Traveler, TSTF-568, Revision 2, “Revise Applicability of BWR/4 TS 3.6.2.5 and TS 3.6.3.2,” for applicability and actions of Technical Specification 3.6.3.3, “Primary Containment Oxygen Concentration.” The changes simplify and clarify the applicability statements, remove the undefined term “scheduled reactor shutdown,” and provide adequate terminal actions.</ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">Public Comments Received as to Proposed NSHC (Yes/No)</ENT>
                        <ENT>No.</ENT>
                    </ROW>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">Tennessee Valley Authority; Watts Bar Nuclear Plant, Units 1 and 2; Rhea County, TN</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket Nos</ENT>
                        <ENT>50-390, 50-391.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Amendment Date</ENT>
                        <ENT>April 15, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession No</ENT>
                        <ENT>ML24072A005.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Amendment Nos</ENT>
                        <ENT>165 (Unit 1) and 72 (Unit 2).</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendments</ENT>
                        <ENT>The amendments revised the Watts Bar Nuclear Plant (Watts Bar), Units 1 and 2, Technical Specification (TS) 4.2.1, “Fuel Assemblies,” to increase the maximum number of tritium producing burnable absorber rods, that can be irradiated in the core to 2,496. The amendments also revised Watts Bar, Unit 1, TS 5.9.6, “Reactor Coolant System (RCS) Pressure and Temperature Limits Report (PTLR),” to be consistent with Watts Bar, Unit 2, TS 5.9.6, and revised both units' TS 5.9.6.b to add WCAP-18124-NP-A Rev. 0 Supplement 1-NP-A, Rev. 0, “Fluence Determination with RAPTOR-M3G and FERRET—Supplement for Extended Beltline Materials.” The amendments also revised the Watts Bar Dual-Unit Update Final Safety Analysis Report to modify the source term for the design basis accident analyses to allow the core fission product inventory to be calculated using an updated version of the ORIGEN code.</ENT>
                    </ROW>
                    <ROW RUL="s">
                        <ENT I="01">Public Comments Received as to Proposed NSHC (Yes/No)</ENT>
                        <ENT>No.</ENT>
                    </ROW>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">Virginia Electric and Power Company, Dominion Nuclear Company; North Anna Power Station, Unit Nos. 1 and 2; Louisa County, VA; Virginia Electric and Power Company; Surry Power Station, Unit Nos. 1 and 2; Surry County, VA</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket Nos</ENT>
                        <ENT>50-280, 50-281, 50-338, 50-339.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Amendment Date</ENT>
                        <ENT>April 22, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession No</ENT>
                        <ENT>ML24054A014.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Amendment Nos</ENT>
                        <ENT>North Anna—297 (Unit 1), 280 (Unit 2); Surry—317 (Unit 1) and 317 (Unit 2).</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendments</ENT>
                        <ENT>The amendments modified the Emergency Plan staffing and staff augmentation times as described in the request, as supplemented.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Public Comments Received as to Proposed NSHC (Yes/No)</ENT>
                        <ENT>No.</ENT>
                    </ROW>
                </GPOTABLE>
                <PRTPAGE P="42003"/>
                <HD SOURCE="HD1">IV. Notice of Issuance of Amendments to Facility Operating Licenses and Combined Licenses and Final Determination of No Significant Hazards Consideration and Opportunity for a Hearing (Exigent Circumstances or Emergency Situation)</HD>
                <P>Since publication of the last monthly notice, the Commission has issued the following amendment. The Commission has determined for this amendment that the application for the amendment complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations. The Commission has made appropriate findings as required by the Act and the Commission's rules and regulations in 10 CFR chapter I, which are set forth in the license amendment.</P>
                <P>Because of exigent circumstances or emergency situation associated with the date the amendment was needed, there was not time for the Commission to publish, for public comment before issuance, its usual notice of consideration of issuance of amendment, proposed NSHC determination, and opportunity for a hearing.</P>
                <P>In circumstances where failure to act in a timely way would have resulted, for example, in derating or shutdown of a nuclear power plant or in prevention of either resumption of operation or of increase in power output up to the plant's licensed power level (an emergency situation), the Commission may not have had an opportunity to provide for public comment on its NSHC determination. In such case, the license amendment has been issued without opportunity for comment prior to issuance. Nonetheless, the State has been consulted by telephone whenever possible.</P>
                <P>
                    Under its regulations, the Commission may issue and make an amendment immediately effective, notwithstanding the pendency before it of a request for a hearing from any person, in advance of the holding and completion of any required hearing, where it has determined that NSHC is involved. The Commission has applied the standards of 10 CFR 50.92 and has made a final determination that the amendment(s) involves NSHC. The basis for this determination is contained in the NRC staff safety evaluation related to each action. Accordingly, the amendment has been issued and made effective as indicated. For those amendments that have not been previously noticed in the 
                    <E T="04">Federal Register</E>
                    , within 60 days after the date of publication of this notice, any persons (petitioner) whose interest may be affected by this action may file a request for a hearing and petition for leave to intervene (petition) with respect to the action. Petitions shall be filed in accordance with the guidance concerning the Commission's “Agency Rules of Practice and Procedure” in 10 CFR part 2 as discussed in section II.A of this document.
                </P>
                <P>Unless otherwise indicated, the Commission has determined that the amendment satisfies the criteria for categorical exclusion in accordance with 10 CFR 51.22. Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared for this amendment. If the Commission has prepared an environmental assessment under the special circumstances provision in 10 CFR 51.12(b) and has made a determination based on that assessment, it is so indicated in the safety evaluation for the amendment.</P>
                <P>
                    For further details with respect to this action, see the amendment and associated documents such as the Commission's letter and safety evaluation, which may be obtained using the ADAMS accession number indicated in the following table. The safety evaluation will provide the ADAMS accession number(s) for the application for amendment and the 
                    <E T="04">Federal Register</E>
                     citation for any environmental assessment. All of these items can be accessed as described in the “Obtaining Information and Submitting Comments” section of this document.
                </P>
                <GPOTABLE COLS="2" OPTS="L2,nj,p1,8/9,i1" CDEF="s100,r100">
                    <TTITLE>License Amendment Issuance—Emergency Circumstances</TTITLE>
                    <BOXHD>
                        <CHED H="1"> </CHED>
                        <CHED H="1"> </CHED>
                    </BOXHD>
                    <ROW EXPSTB="01" RUL="s">
                        <ENT I="21">
                            <E T="02">Nebraska Public Power District; Cooper Nuclear Station; Nemaha County, NE</E>
                        </ENT>
                    </ROW>
                    <ROW EXPSTB="00">
                        <ENT I="01">Docket No</ENT>
                        <ENT>50-298.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Amendment Date</ENT>
                        <ENT>April 5, 2024.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">ADAMS Accession No</ENT>
                        <ENT>ML24096A120.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Amendment No</ENT>
                        <ENT>275.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Brief Description of Amendment</ENT>
                        <ENT>The amendment changed Technical Specification (TS) 3.3.1.1, “Reactor Protection System (RPS) Instrumentation.” Specifically, a temporary footnote was applied immediately to Function 8, “Turbine Stop Valve—Closure,” of TS Table 3.3.1.1-1, “Reactor Protection System Instrumentation.” The current design configuration of the turbine stop valve position switches that input to the RPS did not meet the channel independence criteria. This temporary footnote allows Nebraska Public Power District to not enter the TS 3.3.1.1, Condition A or B for the channel independence condition for a period ending no later than startup from Refuel Outage 33. The amendment was issued under emergency circumstances as provided in the provisions of 10 CFR 50.91(a)(5) because of the time critical nature of the amendment.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Local Media Notice (Yes/No)</ENT>
                        <ENT>No.</ENT>
                    </ROW>
                    <ROW>
                        <ENT I="01">Public Comments Requested as to Proposed NSHC (Yes/No)</ENT>
                        <ENT>No.</ENT>
                    </ROW>
                </GPOTABLE>
                <SIG>
                    <PRTPAGE P="42004"/>
                    <DATED>Dated: May 3, 2024.</DATED>
                    <P>For the Nuclear Regulatory Commission.</P>
                    <NAME>Jamie Pelton,</NAME>
                    <TITLE>Deputy Director, Division of Operating Reactor Licensing, Office of Nuclear Reactor Regulation.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10034 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD> BILLING CODE 7590-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">NUCLEAR REGULATORY COMMISSION</AGENCY>
                <DEPDOC>[Docket No. 99902100; NRC-2024-0078]</DEPDOC>
                <SUBJECT>US SFR Owner, LLC; Construction Permit Application</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Nuclear Regulatory Commission.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice; receipt.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The U.S. Nuclear Regulatory Commission (NRC) is providing public notice each week for four consecutive weeks of receipt and availability of an application for a construction permit for a single unit reactor facility from US SFR Owner, LLC, a wholly owned subsidiary of TerraPower, LLC. The application for the construction permit was received on March 28, 2024, and a supplement to the application was submitted on May 2, 2024.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>May 14, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>Please refer to Docket ID NRC-2024-0078 when contacting the NRC about the availability of information for this action. You may obtain publicly available information related to this action by any of the following methods:</P>
                    <P>
                        • 
                        <E T="03">Federal Rulemaking Website:</E>
                         Go to 
                        <E T="03">https://www.regulations.gov</E>
                         and search for Docket ID NRC-2024-0078. Address questions about Docket IDs in 
                        <E T="03">Regulations.gov</E>
                         to Stacy Schumann; telephone: 301-415-0624; email: 
                        <E T="03">Stacy.Schumann@nrc.gov.</E>
                         For technical questions, contact the individual listed in the 
                        <E T="02">For Further Information Contact</E>
                         section of this document.
                    </P>
                    <P>
                        • 
                        <E T="03">NRC's Agencywide Documents Access and Management System (ADAMS):</E>
                         You may obtain publicly available documents online in the ADAMS Public Documents collection at 
                        <E T="03">https://www.nrc.gov/reading-rm/adams.html.</E>
                         To begin the search, select “Begin Web-based ADAMS Search.” For problems with ADAMS, please contact the NRC's Public Document Room (PDR) reference staff at 1-800-397-4209, at 301-415-4737, or by email to 
                        <E T="03">PDR.Resource@nrc.gov.</E>
                         The ADAMS accession number for each document referenced (if it is available in ADAMS) is provided the first time that it is mentioned in this document.
                    </P>
                    <P>
                        • 
                        <E T="03">NRC's PDR:</E>
                         The PDR, where you may examine and order copies of publicly available documents, is open by appointment. To make an appointment to visit the PDR, please send an email to 
                        <E T="03">PDR.Resource@nrc.gov</E>
                         or call 1-800-397-4209 or 301-415-4737, between 8 a.m. and 4 p.m. eastern time (ET), Monday through Friday, except Federal holidays.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Mallecia Sutton, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-0673, email: 
                        <E T="03">Mallecia.Sutton@nrc.gov.</E>
                    </P>
                    <HD SOURCE="HD1">I. Discussion</HD>
                    <P>
                        On March 28, 2024, TerraPower, LLC (TerraPower), on behalf of US SFR Owner, LLC., a wholly owned subsidiary of TerraPower, filed an application for a construction permit for a single-unit power reactor facility located in Lincoln County, Wyoming, pursuant to section 103 of the Atomic Energy Act, as amended, and part 50 of title 10 of the 
                        <E T="03">Code of Federal Regulations</E>
                         (10 CFR), “Domestic Licensing of Production and Utilization Facilities.” The single-unit facility is to be identified as Kemmerer Power Station, Unit 1 and would be based on the TerraPower and General Electric-Hitachi Natrium reactor design which is a pool-type sodium fast reactor using metal fuel.
                    </P>
                    <P>The application submitted on March 28, 2024, is available in ADAMS under Package Accession No. ML24088A059. Along with other documents, the ADAMS package includes the transmittal letter (ADAMS Accession No. ML24088A060), the preliminary safety analysis report (ADAMS Accession No. ML24088A065), and the environmental report (ADAMS Accession No. ML24088A072). The application was supplemented on May 2, 2024 (ADAMS Accession No. ML24123A242). The information submitted by the applicant includes certain administrative information submitted pursuant to 10 CFR 50.33, such as on financial qualifications; technical information submitted pursuant to 10 CFR 50.34; and the environmental report submitted pursuant to 10 CFR part 51, “Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions.” These notices are being provided in accordance with the requirements in 10 CFR 50.43(a)(3).</P>
                    <P>
                        The NRC staff is currently undertaking its acceptance review of the application. If the application is accepted for docketing, a subsequent 
                        <E T="04">Federal Register</E>
                         notice will be issued that addresses the acceptability of the construction permit application for docketing and provisions for participation of the public in the permitting process.
                    </P>
                    <SIG>
                        <DATED>Dated: May 8, 2024.</DATED>
                        <P>For the Nuclear Regulatory Commission.</P>
                        <NAME>Mallecia A. Sutton,</NAME>
                        <TITLE>Senior Project Manager, Advanced Reactor Licensing Branch 1, Division of Advanced Reactors and Non-Power Production and Utilization Facilities, Office of Nuclear Reactor Regulation.</TITLE>
                    </SIG>
                </FURINF>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10474 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">POSTAL REGULATORY COMMISSION</AGENCY>
                <DEPDOC>[Docket Nos. MC2024-277 and CP2024-283; MC2024-279 and CP2024-284; MC2024-279 and CP2024-285]</DEPDOC>
                <SUBJECT>New Postal Products</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Postal Regulatory Commission.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Commission is noticing a recent Postal Service filing for the Commission's consideration concerning a negotiated service agreement. This notice informs the public of the filing, invites public comment, and takes other administrative steps.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>
                        <E T="03">Comments are due:</E>
                         May 15, 2024.
                    </P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Submit comments electronically via the Commission's Filing Online system at 
                        <E T="03">http://www.prc.gov.</E>
                         Those who cannot submit comments electronically should contact the person identified in the 
                        <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                         section by telephone for advice on filing alternatives.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>David A. Trissell, General Counsel, at 202-789-6820.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">Table of Contents</HD>
                <EXTRACT>
                    <FP SOURCE="FP-2">I. Introduction</FP>
                    <FP SOURCE="FP-2">II. Docketed Proceeding(s)</FP>
                </EXTRACT>
                <HD SOURCE="HD1">I. Introduction</HD>
                <P>
                    The Commission gives notice that the Postal Service filed request(s) for the Commission to consider matters related to negotiated service agreement(s). The request(s) may propose the addition or removal of a negotiated service agreement from the Market Dominant or the Competitive product list, or the modification of an existing product currently appearing on the Market Dominant or the Competitive product list.
                    <PRTPAGE P="42005"/>
                </P>
                <P>Section II identifies the docket number(s) associated with each Postal Service request, the title of each Postal Service request, the request's acceptance date, and the authority cited by the Postal Service for each request. For each request, the Commission appoints an officer of the Commission to represent the interests of the general public in the proceeding, pursuant to 39 U.S.C. 505 (Public Representative). Section II also establishes comment deadline(s) pertaining to each request.</P>
                <P>
                    The public portions of the Postal Service's request(s) can be accessed via the Commission's website (
                    <E T="03">http://www.prc.gov</E>
                    ). Non-public portions of the Postal Service's request(s), if any, can be accessed through compliance with the requirements of 39 CFR 3011.301.
                    <SU>1</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>1</SU>
                         
                        <E T="03">See</E>
                         Docket No. RM2018-3, Order Adopting Final Rules Relating to Non-Public Information, June 27, 2018, Attachment A at 19-22 (Order No. 4679).
                    </P>
                </FTNT>
                <P>The Commission invites comments on whether the Postal Service's request(s) in the captioned docket(s) are consistent with the policies of title 39. For request(s) that the Postal Service states concern Market Dominant product(s), applicable statutory and regulatory requirements include 39 U.S.C. 3622, 39 U.S.C. 3642, 39 CFR part 3030, and 39 CFR part 3040, subpart B. For request(s) that the Postal Service states concern Competitive product(s), applicable statutory and regulatory requirements include 39 U.S.C. 3632, 39 U.S.C. 3633, 39 U.S.C. 3642, 39 CFR part 3035, and 39 CFR part 3040, subpart B. Comment deadline(s) for each request appear in section II.</P>
                <HD SOURCE="HD1">II. Docketed Proceeding(s)</HD>
                <P>
                    1. 
                    <E T="03">Docket No(s).:</E>
                     MC2024-277 and CP2024-283; 
                    <E T="03">Filing Title:</E>
                     USPS Request to Add Priority Mail Express &amp; Priority Mail Contract 138 to Competitive Product List and Notice of Filing Materials Under Seal; 
                    <E T="03">Filing Acceptance Date:</E>
                     May 7, 2024; 
                    <E T="03">Filing Authority:</E>
                     39 U.S.C. 3642, 39 CFR 3040.130 through 3040.135, and 39 CFR 3035.105; 
                    <E T="03">Public Representative:</E>
                     Kenneth R. Moeller; 
                    <E T="03">Comments Due:</E>
                     May 15, 2024.
                </P>
                <P>
                    2. 
                    <E T="03">Docket No(s).:</E>
                     MC2024-278 and CP2024-284; 
                    <E T="03">Filing Title:</E>
                     USPS Request to Add Priority Mail &amp; USPS Ground Advantage Contract 248 to Competitive Product List and Notice of Filing Materials Under Seal; 
                    <E T="03">Filing Acceptance Date:</E>
                     May 7, 2024; 
                    <E T="03">Filing Authority:</E>
                     39 U.S.C. 3642, 39 CFR 3040.130 through 3040.135, and 39 CFR 3035.105; 
                    <E T="03">Public Representative:</E>
                     Kenneth R. Moeller; 
                    <E T="03">Comments Due:</E>
                     May 15, 2024.
                </P>
                <P>
                    3. 
                    <E T="03">Docket No(s).:</E>
                     MC2024-279 and CP2024-285; 
                    <E T="03">Filing Title:</E>
                     USPS Request to Add Priority Mail &amp; USPS Ground Advantage Contract 249 to Competitive Product List and Notice of Filing Materials Under Seal; 
                    <E T="03">Filing Acceptance Date:</E>
                     May 7, 2024; 
                    <E T="03">Filing Authority:</E>
                     39 U.S.C. 3642, 39 CFR 3040.130 through 3040.135, and 39 CFR 3035.105; 
                    <E T="03">Public Representative:</E>
                     Jennaca D. Upperman; 
                    <E T="03">Comments Due:</E>
                     May 15, 2024.
                </P>
                <P>
                    This Notice will be published in the 
                    <E T="04">Federal Register</E>
                    .
                </P>
                <SIG>
                    <NAME>Erica A. Barker,</NAME>
                    <TITLE>Secretary.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10463 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 7710-FW-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">SECURITIES AND EXCHANGE COMMISSION</AGENCY>
                <DEPDOC>[Release No. 34-100077; File No. SR-NSCC-2024-003]</DEPDOC>
                <SUBJECT>Self-Regulatory Organizations; National Securities Clearing Corporation; Notice of Designation of Longer Period for Commission Action on Proposed Rule Change To Amend the Clearing Agency Risk Management Framework</SUBJECT>
                <DATE>May 8, 2024.</DATE>
                <P>
                    On March 11, 2024, National Securities Clearing Corporation (“NSCC”) filed with the Securities and Exchange Commission (“Commission”) the proposed rule change SR-NSCC-2024-003 (“Proposed Rule Change”) pursuant to section 19(b) of the Securities Exchange Act of 1934 (“Exchange Act”) 
                    <SU>1</SU>
                    <FTREF/>
                     and Rule 19b-4 
                    <SU>2</SU>
                    <FTREF/>
                     thereunder to amend the Clearing Agency Risk Management Framework of NSCC and its affiliates, The Depository Trust Company (“DTC”) and Fixed Income Clearing Corporation (“FICC,” and together with NSCC and DTC, the “Clearing Agencies”) to describe how the Clearing Agencies may solicit views of participants and other industry stakeholders, and to provide for the annual assessment and subsequent review of FICC's Government Securities Division access models by FICC's Board of Directors.
                    <SU>3</SU>
                    <FTREF/>
                     The Proposed Rule Change was published for public comment in the 
                    <E T="04">Federal Register</E>
                     on March 26, 2024.
                    <SU>4</SU>
                    <FTREF/>
                     The Commission has received comments regarding the substance of the changes proposed in the Proposed Rule Change.
                    <SU>5</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>1</SU>
                         15 U.S.C. 78s(b)(1).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>2</SU>
                         17 CFR 240.19b-4.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>3</SU>
                         
                        <E T="03">See</E>
                         Notice of Filing 
                        <E T="03">infra</E>
                         note 4, at 89 FR 21091.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>4</SU>
                         Securities Exchange Act Release No. 99803 (March 20, 2024), 89 FR 21091 (March 26, 2024) (File No. SR-NSCC-2024-003) (“Notice of Filing”).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>5</SU>
                         Comments on the Proposed Rule Change were received under an affiliated filing and are available at 
                        <E T="03">https://www.sec.gov/comments/sr-ficc-2024-006/srficc2024006.htm.</E>
                    </P>
                </FTNT>
                <P>
                    Section 19(b)(2)(i) of the Exchange Act 
                    <SU>6</SU>
                    <FTREF/>
                     provides that, within 45 days of the publication of notice of the filing of a proposed rule change, the Commission shall either approve the proposed rule change, disapprove the proposed rule change, or institute proceedings to determine whether the proposed rule change should be disapproved unless the Commission extends the period within which it must act as provided in section 19(b)(2)(ii) of the Exchange Act.
                    <SU>7</SU>
                    <FTREF/>
                     Section 19(b)(2)(ii) of the Exchange Act allows the Commission to designate a longer period for review (up to 90 days from the publication of notice of the filing of a proposed rule change) if the Commission finds such longer period to be appropriate and publishes its reasons for so finding, or as to which the self-regulatory organization consents.
                    <SU>8</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>6</SU>
                         15 U.S.C. 78s(b)(2)(i).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>7</SU>
                         15 U.S.C. 78 s(b)(2)(ii).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>8</SU>
                         
                        <E T="03">Id.</E>
                    </P>
                </FTNT>
                <P>The 45th day after publication of the Notice of Filing is May 10, 2024. In order to provide the Commission with sufficient time to consider the Proposed Rule Change, the Commission finds that it is appropriate to designate a longer period within which to take action on the Proposed Rule Change and therefore is extending this 45-day time period.</P>
                <P>
                    Accordingly, the Commission, pursuant to section 19(b)(2) of the Exchange Act,
                    <SU>9</SU>
                    <FTREF/>
                     designates June 24, 2024, as the date by which the Commission shall either approve, disapprove, or institute proceedings to determine whether to disapprove proposed rule change SR-NSCC-2024-003.
                </P>
                <FTNT>
                    <P>
                        <SU>9</SU>
                         
                        <E T="03">Id.</E>
                    </P>
                </FTNT>
                <SIG>
                    <P>
                        For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
                        <SU>10</SU>
                        <FTREF/>
                    </P>
                    <FTNT>
                        <P>
                            <SU>10</SU>
                             17 CFR 200.30-3(a)(12).
                        </P>
                    </FTNT>
                    <NAME>Sherry R. Haywood,</NAME>
                    <TITLE>Assistant Secretary.</TITLE>
                </SIG>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10430 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 8011-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <PRTPAGE P="42006"/>
                <AGENCY TYPE="S">SECURITIES AND EXCHANGE COMMISSION</AGENCY>
                <DEPDOC>[Release No. 34-100076; File No. SR-DTC-2024-003]</DEPDOC>
                <SUBJECT>Self-Regulatory Organizations; Depository Trust Company; Notice of Designation of Longer Period for Commission Action on Proposed Rule Change To Amend the Clearing Agency Risk Management Framework</SUBJECT>
                <DATE>May 8, 2024.</DATE>
                <P>
                    On March 11, 2024, The Depository Trust Company (“DTC”) filed with the Securities and Exchange Commission (“Commission”) the proposed rule change SR-DTC-2024-003 (“Proposed Rule Change”) pursuant to Section 19(b) of the Securities Exchange Act of 1934 (“Exchange Act”) 
                    <SU>1</SU>
                    <FTREF/>
                     and Rule 19b-4 
                    <SU>2</SU>
                    <FTREF/>
                     thereunder to amend the Clearing Agency Risk Management Framework of DTC and its affiliates, Fixed Income Clearing Corporation (“FICC”) and National Securities Clearing Corporation (“NSCC,” and together with FICC and NSCC, the “Clearing Agencies”) to describe how the Clearing Agencies may solicit views of participants and other industry stakeholders, and to provide for the annual assessment and subsequent review of FICC's Government Securities Division access models by FICC's Board of Directors.
                    <SU>3</SU>
                    <FTREF/>
                     The Proposed Rule Change was published for public comment in the 
                    <E T="04">Federal Register</E>
                     on March 26, 2024.
                    <SU>4</SU>
                    <FTREF/>
                     The Commission has received comments regarding the substance of the changes proposed in the Proposed Rule Change.
                    <SU>5</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>1</SU>
                         15 U.S.C. 78s(b)(1).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>2</SU>
                         17 CFR 240.19b-4.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>3</SU>
                         
                        <E T="03">See</E>
                         Notice of Filing 
                        <E T="03">infra</E>
                         note 4, at 89 FR 21118.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>4</SU>
                         Securities Exchange Act Release No. 99802 (March 20, 2024), 89 FR 21118 (March 26, 2024) (File No. SR-DTC-2024-003) (“Notice of Filing”).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>5</SU>
                         Comments on the Proposed Rule Change were received under an affiliated filing and are available at 
                        <E T="03">https://www.sec.gov/comments/sr-ficc-2024-006/srficc2024006.htm.</E>
                    </P>
                </FTNT>
                <P>
                    Section 19(b)(2)(i) of the Exchange Act 
                    <SU>6</SU>
                    <FTREF/>
                     provides that, within 45 days of the publication of notice of the filing of a proposed rule change, the Commission shall either approve the proposed rule change, disapprove the proposed rule change, or institute proceedings to determine whether the proposed rule change should be disapproved unless the Commission extends the period within which it must act as provided in Section 19(b)(2)(ii) of the Exchange Act.
                    <SU>7</SU>
                    <FTREF/>
                     Section 19(b)(2)(ii) of the Exchange Act allows the Commission to designate a longer period for review (up to 90 days from the publication of notice of the filing of a proposed rule change) if the Commission finds such longer period to be appropriate and publishes its reasons for so finding, or as to which the self-regulatory organization consents.
                    <SU>8</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>6</SU>
                         15 U.S.C. 78s(b)(2)(i).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>7</SU>
                         15 U.S.C. 78 s(b)(2)(ii).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>8</SU>
                         
                        <E T="03">Id.</E>
                    </P>
                </FTNT>
                <P>The 45th day after publication of the Notice of Filing is May 10, 2024. In order to provide the Commission with sufficient time to consider the Proposed Rule Change, the Commission finds that it is appropriate to designate a longer period within which to take action on the Proposed Rule Change and therefore is extending this 45-day time period.</P>
                <P>
                    Accordingly, the Commission, pursuant to Section 19(b)(2) of the Exchange Act,
                    <SU>9</SU>
                    <FTREF/>
                     designates June 24, 2024, as the date by which the Commission shall either approve, disapprove, or institute proceedings to determine whether to disapprove proposed rule change SR-DTC-2024-003.
                </P>
                <FTNT>
                    <P>
                        <SU>9</SU>
                         
                        <E T="03">Id.</E>
                    </P>
                </FTNT>
                <P>
                    For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
                    <SU>10</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>10</SU>
                         17 CFR 200.30-3(a)(12).
                    </P>
                </FTNT>
                <SIG>
                    <NAME>Sherry R. Haywood,</NAME>
                    <TITLE>Assistant Secretary.</TITLE>
                </SIG>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10429 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 8011-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">SECURITIES AND EXCHANGE COMMISSION</AGENCY>
                <DEPDOC>[Release No. 34-100075; File No. SR-FICC-2024-006]</DEPDOC>
                <SUBJECT>Self-Regulatory Organizations; Fixed Income Clearing Corporation; Notice of Designation of Longer Period for Commission Action on Proposed Rule Change To Amend the Clearing Agency Risk Management Framework</SUBJECT>
                <DATE>May 8, 2024.</DATE>
                <P>
                    On March 11, 2024, Fixed Income Clearing Corporation (“FICC”) filed with the Securities and Exchange Commission (“Commission”) the proposed rule change SR-FICC-2024-006 (“Proposed Rule Change”) pursuant to section 19(b) of the Securities Exchange Act of 1934 (“Exchange Act”) 
                    <SU>1</SU>
                    <FTREF/>
                     and Rule 19b-4 
                    <SU>2</SU>
                    <FTREF/>
                     thereunder to amend the Clearing Agency Risk Management Framework of FICC and its affiliates, The Depository Trust Company (“DTC”) and National Securities Clearing Corporation (“NSCC,” and together with FICC and DTC, the “Clearing Agencies”) to describe how the Clearing Agencies may solicit views of participants and other industry stakeholders and to provide for the annual assessment and subsequent review of FICC's Government Securities Division access models by FICC's Board of Directors.
                    <SU>3</SU>
                    <FTREF/>
                     The Proposed Rule Change was published for public comment in the 
                    <E T="04">Federal Register</E>
                     on March 26, 2024.
                    <SU>4</SU>
                    <FTREF/>
                     The Commission has received comments regarding the substance of the changes proposed in the Proposed Rule Change.
                    <SU>5</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>1</SU>
                         15 U.S.C. 78s(b)(1).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>2</SU>
                         17 CFR 240.19b-4.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>3</SU>
                         
                        <E T="03">See</E>
                         Notice of Filing 
                        <E T="03">infra</E>
                         note 4, at 89 FR 21068.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>4</SU>
                         Securities Exchange Act Release No. 99805 (March 20, 2024), 89 FR 21068 (March 26, 2024) (File No. SR-FICC-2024-006) (“Notice of Filing”).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>5</SU>
                         Comments on the Proposed Rule Change are available at 
                        <E T="03">https://www.sec.gov/comments/sr-ficc-2024-006/srficc2024006.htm.</E>
                    </P>
                </FTNT>
                <P>
                    Section 19(b)(2)(i) of the Exchange Act 
                    <SU>6</SU>
                    <FTREF/>
                     provides that, within 45 days of the publication of notice of the filing of a proposed rule change, the Commission shall either approve the proposed rule change, disapprove the proposed rule change, or institute proceedings to determine whether the proposed rule change should be disapproved unless the Commission extends the period within which it must act as provided in Section 19(b)(2)(ii) of the Exchange Act.
                    <SU>7</SU>
                    <FTREF/>
                     Section 19(b)(2)(ii) of the Exchange Act allows the Commission to designate a longer period for review (up to 90 days from the publication of notice of the filing of a proposed rule change) if the Commission finds such longer period to be appropriate and publishes its reasons for so finding, or as to which the self-regulatory organization consents.
                    <SU>8</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>6</SU>
                         15 U.S.C. 78s(b)(2)(i).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>7</SU>
                         15 U.S.C. 78 s(b)(2)(ii).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>8</SU>
                         
                        <E T="03">Id.</E>
                    </P>
                </FTNT>
                <P>The 45th day after publication of the Notice of Filing is May 10, 2024. In order to provide the Commission with sufficient time to consider the Proposed Rule Change, the Commission finds that it is appropriate to designate a longer period within which to take action on the Proposed Rule Change and therefore is extending this 45-day time period.</P>
                <P>
                    Accordingly, the Commission, pursuant to section 19(b)(2) of the Exchange Act,
                    <SU>9</SU>
                    <FTREF/>
                     designates June 24, 2024, as the date by which the Commission shall either approve, disapprove, or institute proceedings to determine whether to disapprove proposed rule change SR-FICC-2024-006.
                </P>
                <FTNT>
                    <P>
                        <SU>9</SU>
                         
                        <E T="03">Id.</E>
                    </P>
                </FTNT>
                <SIG>
                    <PRTPAGE P="42007"/>
                    <P>
                        For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
                        <SU>10</SU>
                        <FTREF/>
                    </P>
                    <FTNT>
                        <P>
                            <SU>10</SU>
                             17 CFR 200.30-3(a)(12).
                        </P>
                    </FTNT>
                    <NAME>Sherry R. Haywood,</NAME>
                    <TITLE>Assistant Secretary.</TITLE>
                </SIG>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10435 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 8011-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">SECURITIES AND EXCHANGE COMMISSION</AGENCY>
                <DEPDOC>[Release No. 34-100080; File No. SR-NYSE-2023-36]</DEPDOC>
                <SUBJECT>Self-Regulatory Organizations; New York Stock Exchange LLC; Notice of Designation of a Longer Period for Commission Action on Proceedings To Determine Whether To Approve or Disapprove a Proposed Rule Change Regarding Enhancements to Its DMM Program</SUBJECT>
                <DATE>May 8, 2024.</DATE>
                <P>
                    On October 23, 2003, New York Stock Exchange LLC (“NYSE” or “Exchange”) filed with the Securities and Exchange Commission (“Commission”), pursuant to section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”) 
                    <SU>1</SU>
                    <FTREF/>
                     and Rule 19b-4 thereunder,
                    <SU>2</SU>
                    <FTREF/>
                     a proposed rule change to amend its Designated Market Maker (“DMM”) program. The proposed rule change was published for comment in the 
                    <E T="04">Federal Register</E>
                     on November 13, 2023.
                    <SU>3</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>1</SU>
                         15 U.S.C. 78s(b)(1).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>2</SU>
                         17 CFR 240.19b-4.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>3</SU>
                         
                        <E T="03">See</E>
                         Securities Exchange Act Release No. 98869 (November 6, 2023), 88 FR 77625 (November 13, 2023) (SR-NYSE-2023-36). Comments on the proposed rule change are available at: 
                        <E T="03">https://www.sec.gov/comments/sr-nyse-2023-36/srnyse202336.htm.</E>
                    </P>
                </FTNT>
                <P>
                    On December 13, 2023, pursuant to section 19(b)(2) of the Act,
                    <SU>4</SU>
                    <FTREF/>
                     the Commission designated a longer period within which to approve the proposed rule change, disapprove the proposed rule change, or institute proceedings to determine whether to disapprove the proposed rule change.
                    <SU>5</SU>
                    <FTREF/>
                     On February 9, 2024, the Commission instituted proceedings under section 19(b)(2)(B) of the Act 
                    <SU>6</SU>
                    <FTREF/>
                     to determine whether to approve or disapprove the proposed rule change.
                    <SU>7</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>4</SU>
                         15 U.S.C. 78s(b)(2).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>5</SU>
                         
                        <E T="03">See</E>
                         Securities Exchange Act Release No. 99161 (December 13, 2023), 88 FR 87829 (December 19, 2023).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>6</SU>
                         15 U.S.C. 78s(b)(2)(B).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>7</SU>
                         
                        <E T="03">See</E>
                         Securities Exchange Act Release No. 99511, 89 FR 11893 (Feb. 15, 2024).
                    </P>
                </FTNT>
                <P>
                    Section 19(b)(2) of the Act 
                    <SU>8</SU>
                    <FTREF/>
                     provides that, after initiating proceedings, the Commission shall issue an order approving or disapproving the proposed rule change not later than 180 days after the date of publication of notice of filing of the proposed rule change. The Commission may extend the period for issuing an order approving or disapproving the proposed rule change, however, by not more than 60 days if the Commission determines that a longer period is appropriate and publishes the reasons for such determination. The proposed rule change was published for comment in the 
                    <E T="04">Federal Register</E>
                     on November 13, 2023.
                    <SU>9</SU>
                    <FTREF/>
                     The 180th day after publication of the proposed rule change is May 11, 2024. The Commission is extending the time period for approving or disapproving the proposed rule change for an additional 60 days.
                </P>
                <FTNT>
                    <P>
                        <SU>8</SU>
                         15 U.S.C. 78s(b)(2).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>9</SU>
                         
                        <E T="03">See supra</E>
                         note 3 and accompanying text.
                    </P>
                </FTNT>
                <P>
                    The Commission finds that it is appropriate to designate a longer period within which to issue an order approving or disapproving the proposed rule change so that it has sufficient time to consider the proposed rule change and the issues raised therein. Accordingly, the Commission, pursuant to Section 19(b)(2) of the Act,
                    <SU>10</SU>
                    <FTREF/>
                     designates July 10, 2024, as the date by which the Commission shall either approve or disapprove the proposed rule change (File No. SR-NYSE-2023-36).
                </P>
                <FTNT>
                    <P>
                        <SU>10</SU>
                         15 U.S.C. 78s(b)(2).
                    </P>
                </FTNT>
                <SIG>
                    <P>
                        For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
                        <SU>11</SU>
                        <FTREF/>
                    </P>
                    <FTNT>
                        <P>
                            <SU>11</SU>
                             17 CFR 200.30-3(a)(57).
                        </P>
                    </FTNT>
                    <NAME>Sherry R. Haywood,</NAME>
                    <TITLE>Assistant Secretary.</TITLE>
                </SIG>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10431 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 8011-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">SECURITIES AND EXCHANGE COMMISSION</AGENCY>
                <DEPDOC>[Release No. 34-100081; File No. SR-CBOE-2024-015]</DEPDOC>
                <SUBJECT>Self-Regulatory Organizations; Cboe Exchange, Inc.; Notice of Filing of Amendment No. 1 and Order Granting Accelerated Approval of a Proposed Rule Change, as Modified by Amendment No. 1, To Amend Exchange Rule 5.33, Complex Orders</SUBJECT>
                <DATE>May 8, 2024.</DATE>
                <HD SOURCE="HD1">I. Introduction</HD>
                <P>
                    On March 19, 2024, Cboe Exchange, Inc. (“Exchange” or “Cboe Options”) filed with the Securities and Exchange Commission (“Commission”), pursuant to section 19(b)(1) of the Securities Exchange Act of 1934 (“Exchange Act”) 
                    <SU>1</SU>
                    <FTREF/>
                     and Rule 19b-4 thereunder,
                    <SU>2</SU>
                    <FTREF/>
                     a proposed rule change to amend the definition of “complex strategy” in Exchange Rule 5.33(a) to allow the Exchange to create new complex strategies. In addition, the proposal amends Exchange Rule 5.33(b)(2) to provide that, in a class in which the Exchange determines that complex orders with Capacity M or N are not eligible for entry into the Complex Order Book (“COB”), the Exchange may determine that a complex order with Capacity M or N may enter the COB in complex strategies designated by the Exchange.
                    <SU>3</SU>
                    <FTREF/>
                     The proposed rule change was published for comment in the 
                    <E T="04">Federal Register</E>
                     on March 28, 2024.
                    <SU>4</SU>
                    <FTREF/>
                     On April 4, 2024, the Exchange filed Amendment No. 1 to the proposed rule change.
                    <SU>5</SU>
                    <FTREF/>
                     The Commission has received no comment letters regarding the proposal. The Commission is publishing this notice to solicit comment on Amendment No. 1 and is approving the proposed rule change, as modified by Amendment No. 1, on an accelerated basis.
                </P>
                <FTNT>
                    <P>
                        <SU>1</SU>
                         15 U.S.C. 78s(b)(1).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>2</SU>
                         17 CFR 240.19b-4.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>3</SU>
                         The Exchange states that the origin code “M” represents Exchange Market-Makers, and the origin code “N” represents market makers or specialists on another exchange (“away market makers”). The Exchange states that, currently, orders representing any capacity, including M and N, are eligible for entry and may rest on the COB in all classes except S&amp;P 500 Index (“SPX”) and Cboe Volatility Index (“VIX”) options. In SPX and VIX options, M and N complex orders are not eligible for entry into the COB except as set forth in Exchange Rule 5.33(b)(2). 
                        <E T="03">See</E>
                         Securities Exchange Act Release No. 99838 (March 22, 2024), 89 FR 21548, 21549, n.3 (March 28, 2024) (“Notice”) and Amendment No. 1.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>4</SU>
                         
                        <E T="03">See</E>
                         Notice, 
                        <E T="03">supra</E>
                         note 3.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>5</SU>
                         Amendment No. 1 revises the proposal to correct descriptions of the current complex book process by stating that Market-Makers and away market makers currently are not permitted to enter orders in VIX options, as well as SPX options, in the COB. Amendment No. 1 makes no changes to Exhibit 5 of the proposal. Amendment No. 1 is available on the Commission's website at 
                        <E T="03">https://www.sec.gov/comments/sr-cboe-2024-015/srcboe2024015.htm.</E>
                    </P>
                </FTNT>
                <HD SOURCE="HD1">II. Description of the Proposed Rule Change, as Modified by Amendment No. 1</HD>
                <P>
                    The definition of complex strategy in Exchange Rule 5.33(a) provides that new complex strategies may be created as the result of the receipt of a complex instrument creation request or the receipt of a complex order for a complex strategy that is not currently in the Exchange's system.
                    <SU>6</SU>
                    <FTREF/>
                     The Exchange proposes to revise this definition to also allow the Exchange to create new complex strategies. The Exchange states that customers will continue to have the 
                    <PRTPAGE P="42008"/>
                    ability to create complex instruments as they do today.
                    <SU>7</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>6</SU>
                         
                        <E T="03">See</E>
                         Cboe Rule 5.33(a).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>7</SU>
                         
                        <E T="03">See</E>
                         Notice, 89 FR at 21550.
                    </P>
                </FTNT>
                <P>
                    Exchange Rule 5.33(b)(2) states, in part, that the Exchange determines which Capacities are eligible for entry into the COB.
                    <SU>8</SU>
                    <FTREF/>
                     The Exchange states that, currently, orders entered with any Capacity, including Market-Maker and away market-maker orders, are eligible for entry and may rest on the COB in all classes except SPX and VIX.
                    <SU>9</SU>
                    <FTREF/>
                     In SPX and VIX options, Market-Maker and away market maker complex orders are not eligible for entry into the COB except as set forth in Exchange Rule 5.33(b)(2)(A).
                    <SU>10</SU>
                    <FTREF/>
                     The Exchange proposes to amend Exchange Rule 5.33(b)(2) to provides that in a class in which the Exchange determines that orders with Capacity M or N are not eligible for entry into the COB, the Exchange may determine that a complex order with Capacity M or N may enter the COB in complex strategies designated by the Exchange. The Exchange will have the ability to designate strategies created by the Exchange and by users for the entry of Market-Maker and away market maker orders in the COB.
                    <SU>11</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>8</SU>
                         “Capacity” means the capacity in which a User submits an order, which the User specifies by applying the corresponding code to the order. 
                        <E T="03">See</E>
                         Cboe Rule 1.1.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>9</SU>
                         
                        <E T="03">See</E>
                         Amendment No. 1.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>10</SU>
                         
                        <E T="03">See id.</E>
                         Exchange Rule 5.33(b)(2)(A) provides that “In a class in which the Exchange determines complex orders with Capacity M or N are not eligible for entry into the COB, the Exchange may determine that a complex order with Capacity M or N may enter the COB if: (i) the complex order is on the opposite side of (a) a Priority Customer complex order(s) resting in the COB with a price not outside the SNBBO; or (b) orders on the same side of the market in the same complex strategy that initiated a COA(s) if there are “x” number of COAs within “y” milliseconds, counted on a rolling basis (the Exchange determines the number “x” (which must be at least two) and the time period “y” (which may be no more than 2,000); and (ii) the User cancels the complex order, if it remains unexecuted, no later than a specified time (which the Exchange determines and may be no more than five minutes) after the time the COB receives the M or N complex order.”
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>11</SU>
                         
                        <E T="03">See</E>
                         Notice, 89 FR at 21550.
                    </P>
                </FTNT>
                <P>
                    When determining which complex strategies to create and in which complex strategies the orders of Market-Makers and away market makers will be eligible for COB entry, the Exchange represents that it intends to make such determinations based on objective, nondiscriminatory factors, including strategy type, orders, and executions within a strategy type using close by strikes, and market participant feedback.
                    <SU>12</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>12</SU>
                         
                        <E T="03">See id.</E>
                         at 21552.
                    </P>
                </FTNT>
                <HD SOURCE="HD1">III. Discussion and Commission Findings</HD>
                <P>
                    After careful review, the Commission finds that the proposed rule change, as modified by Amendment No. 1, is consistent with the requirements of the Act and the rules and regulations thereunder applicable to a national securities exchange.
                    <SU>13</SU>
                    <FTREF/>
                     In particular, the Commission finds that the proposed rule change is consistent with Section 6(b)(5) of the Act,
                    <SU>14</SU>
                    <FTREF/>
                     which requires, among other things, that the rules of a national securities exchange be designed to prevent fraudulent and manipulative acts and practices, to promote just and equitable principles of trade, to remove impediments to and perfect the mechanism of a free and open market and a national market system, and, in general, to protect investors and the public interest, and not be designed to permit unfair discrimination between customers, issuers, brokers, or dealers.
                </P>
                <FTNT>
                    <P>
                        <SU>13</SU>
                         In approving this proposed rule change, the Commission has considered the proposed rule's impact on efficiency, competition, and capital formation. 
                        <E T="03">See</E>
                         15 U.S.C. 78c(f).
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>14</SU>
                         15 U.S.C. 78f(b)(5).
                    </P>
                </FTNT>
                <P>
                    The proposal will allow the Exchange to create complex strategies and to determine, in classes for which the Exchange has determined that the orders of Market-Makers and away market makers may not rest in the COB, that the orders of Market-Makers and away market makers may rest in the COB in complex strategies designated by the Exchange. As described more fully in the Notice, the Exchange states that it understands from market participants that electronic trading in complex strategies may be limited for a variety of reasons, including the fragmentation of liquidity across multiple customer-created complex instruments expressing a similar exposure profile.
                    <SU>15</SU>
                    <FTREF/>
                     The Exchange states that allowing it to create complex strategies, and to designate complex strategies in which the orders of Market-Makers and away market makers are eligible for entry in the COB, would permit the consolidation of liquidity in a single complex strategy that currently is spread across multiple customer-created complex instruments expressing the same or similar exposure profiles.
                    <SU>16</SU>
                    <FTREF/>
                     The Exchange further states that the proposal to allow the Exchange to create complex strategies could aggregate liquidity seeking a particular level of risk exposure in a single set of strikes for a complex strategy (as opposed to across many varying strikes).
                    <SU>17</SU>
                    <FTREF/>
                     According to the Exchange, the consolidation of liquidity resulting from the proposed changes could increase execution opportunities at more competitive prices.
                    <SU>18</SU>
                    <FTREF/>
                     The Commission believes that consolidating liquidity in particular complex strategies, including commonly traded strategies, could increase price competition in these strategies, potentially resulting in more favorable executions for investors. The Exchange represents that it will determine the complex strategies to create and the complex strategies in in which the orders of Market-Makers and away market makers will be eligible for COB entry based on objective and nondiscriminatory factors, including the strategy type, orders, and executions within a strategy type using close by strikes, and market participant feedback.
                    <SU>19</SU>
                    <FTREF/>
                     In addition, the Exchange states that customers will continue to have the ability to create complex instruments as they do today.
                    <SU>20</SU>
                    <FTREF/>
                </P>
                <FTNT>
                    <P>
                        <SU>15</SU>
                         
                        <E T="03">See</E>
                         Notice, 89 FR at 21549.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>16</SU>
                         
                        <E T="03">See</E>
                         Notice, 89 FR at 21459, 21550.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>17</SU>
                         
                        <E T="03">See</E>
                         Notice, 89 FR at 21550.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>18</SU>
                         
                        <E T="03">See id.</E>
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>19</SU>
                         
                        <E T="03">See</E>
                         Notice, 89 FR at 21552.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>20</SU>
                         
                        <E T="03">See id.</E>
                         at 21550. 
                        <E T="03">See also</E>
                         Exchange Rule 5.33(a) (definition of complex strategy).
                    </P>
                </FTNT>
                <HD SOURCE="HD1">IV. Solicitation of Comments on Amendment No. 1 to the Proposed Rule Change</HD>
                <P>Interested persons are invited to submit written data, views, and arguments concerning whether Amendment No. 1 is consistent with the Act. Comments may be submitted by any of the following methods:</P>
                <HD SOURCE="HD2">Electronic Comments</HD>
                <P>
                    • Use the Commission's internet comment form (
                    <E T="03">http://www.sec.gov/rules/sro.shtml</E>
                    ); or
                </P>
                <P>
                    • Send an email to 
                    <E T="03">rule-comments@sec.gov.</E>
                     Please include File Number SR-CBOE-2024-015 on the subject line.
                </P>
                <HD SOURCE="HD2">Paper Comments</HD>
                <P>• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE, Washington, DC 20549-1090.</P>
                <FP>
                    All submissions should refer to file number SR-CBOE-2024-015. This file number should be included on the subject line if email is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's internet website 
                    <E T="03">(https://www.sec.gov/rules/sro.shtml).</E>
                     Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule 
                    <PRTPAGE P="42009"/>
                    change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for website viewing and printing in the Commission's Public Reference Room, 100 F Street NE, Washington, DC 20549, on official business days between the hours of 10 a.m. and 3 p.m. Copies of the filing also will be available for inspection and copying at the principal office of the Exchange. Do not include personal identifiable information in submissions; you should submit only information that you wish to make available publicly. We may redact in part or withhold entirely from publication submitted material that is obscene or subject to copyright protection. All submissions should refer to file number SR-CBOE-2024-015 and should be submitted on or before June 4, 2024.
                </FP>
                <HD SOURCE="HD1">V. Accelerated Approval of Proposed Rule Change, as Modified by Amendment No. 1</HD>
                <P>
                    The Commission finds good cause to approve the proposed rule change, as modified by Amendment No. 1, prior to the thirtieth day after the date of publication of notice of the filing of Amendment No. 1 in the 
                    <E T="04">Federal Register</E>
                    . The proposal, as originally filed, stated that SPX is the only option class for which the Exchange has determined that the orders of Market-Makers and away market makers are not eligible for entry in the COB.
                    <SU>21</SU>
                    <FTREF/>
                     Amendment No. 1 revises the proposal to indicate that the Exchange has determined that the orders of Market-Makers and away market makers in VIX options, as well as SPX options, are not eligible for entry in the COB. Amendment No. 1 does not modify the rule text or the operation of the proposed rules; rather it corrects an erroneous factual statement regarding the option classes for which the Exchange has determined that the orders of Market-Makers and away market makers are not eligible to rest in the COB. Accordingly, the Commission finds good cause, pursuant to Section 19(b)(2) of the Act,
                    <SU>22</SU>
                    <FTREF/>
                     to approve the proposed rule change, as modified by Amendment No. 1, on an accelerated basis.
                </P>
                <FTNT>
                    <P>
                        <SU>21</SU>
                         
                        <E T="03">See</E>
                         Notice, 89 FR at 21549, n.3 and n.4.
                    </P>
                </FTNT>
                <FTNT>
                    <P>
                        <SU>22</SU>
                         15 U.S.C. 78s(b)(2).
                    </P>
                </FTNT>
                <HD SOURCE="HD1">VI. Conclusion</HD>
                <P>
                    <E T="03">It is therefore ordered,</E>
                     pursuant to section 19(b)(2) of the Act,
                    <SU>23</SU>
                    <FTREF/>
                     that the proposed rule change (SR-CBOE-2024-015), as modified by Amendment No. 1, is approved.
                </P>
                <FTNT>
                    <P>
                        <SU>23</SU>
                         15 U.S.C. 78s(b)(2).
                    </P>
                </FTNT>
                <SIG>
                    <P>
                        For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
                        <SU>24</SU>
                        <FTREF/>
                    </P>
                    <FTNT>
                        <P>
                            <SU>24</SU>
                             17 CFR 200.30-3(a)(12).
                        </P>
                    </FTNT>
                    <NAME>Sherry R. Haywood,</NAME>
                    <TITLE>Assistant Secretary.</TITLE>
                </SIG>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10432 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 8011-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">SECURITIES AND EXCHANGE COMMISSION</AGENCY>
                <DEPDOC>[Investment Company Act Release No. 35190; 812-15547]</DEPDOC>
                <SUBJECT>John Hancock Multi Asset Credit Fund, et al.</SUBJECT>
                <DATE>May 9, 2024.</DATE>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Securities and Exchange Commission (“Commission” or “SEC”).</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <P>Notice of an application under section 6(c) of the Investment Company Act of 1940 (the “Act”) for an exemption from sections 18(a)(2), 18(c) and 18(i) of the Act, under sections 6(c) and 23(c) of the Act for an exemption from rule 23c-3 under the Act, and for an order pursuant to section 17(d) of the Act and rule 17d-1 under the Act.</P>
                <P>
                    <E T="03">Summary of Application:</E>
                     Applicants request an order to permit certain registered closed-end investment companies to issue multiple classes of shares and to impose asset-based distribution and/or service fees and early withdrawal charges.
                </P>
                <P>
                    <E T="03">Applicants:</E>
                     John Hancock Multi Asset Credit Fund, John Hancock Asset-Based Lending Fund, Manulife Private Credit Plus Fund and John Hancock Investment Management LLC.
                </P>
                <P>
                    <E T="03">Filing Dates:</E>
                     The application was filed on February 1, 2024 and amended on April 11, 2024, April 30, 2024 and May 8, 2024.
                </P>
                <P>
                    <E T="03">Hearing or Notification of Hearing:</E>
                     An order granting the requested relief will be issued unless the Commission orders a hearing. Interested persons may request a hearing on any application by emailing the SEC's Secretary at 
                    <E T="03">Secretarys-Office@sec.gov</E>
                     and serving the Applicants with a copy of the request by email, if an email address is listed for the relevant Applicant below, or personally or by mail, if a physical address is listed for the relevant Applicant below. Hearing requests should be received by the Commission by 5:30 p.m. on June 3, 2024, and should be accompanied by proof of service on the Applicants, in the form of an affidavit, or, for lawyers, a certificate of service. Pursuant to rule 0-5 under the Act, hearing requests should state the nature of the writer's interest, any facts bearing upon the desirability of a hearing on the matter, the reason for the request, and the issues contested. Persons who wish to be notified of a hearing may request notification by emailing the Commission's Secretary.
                </P>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        The Commission: 
                        <E T="03">Secretarys-Office@sec.gov.</E>
                         Applicants: Christopher Sechler, Esq., 
                        <E T="03">CSechler@jhancock.com,</E>
                         with a copy to Mark P. Goshko, K&amp;L Gates, LLP, 
                        <E T="03">Mark.Goshko@klgates.com,</E>
                         and Pablo J Man, K&amp;L Gates, LLP, 
                        <E T="03">Pablo.Man@klgates.com.</E>
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Trace W. Rakestraw, Senior Special Counsel, at (202) 551-6825 (Division of Investment Management, Chief Counsel's Office).</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    For Applicants' representations, legal analysis, and conditions, please refer to Applicants' application, dated May 8, 2024, which may be obtained via the Commission's website by searching for the file number at the top of this document, or for an Applicant using the Company name search field on the SEC's EDGAR system. The SEC's EDGAR system may be searched at 
                    <E T="03">https://www.sec.gov/edgar/searchedgar/legacy/companysearch.html.</E>
                     You may also call the SEC's Public Reference Room at (202) 551-8090.
                </P>
                <SIG>
                    <P>For the Commission, by the Division of Investment Management, under delegated authority.</P>
                    <NAME>Sherry R. Haywood,</NAME>
                    <TITLE>Assistant Secretary.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10506 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 8011-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">SECURITIES AND EXCHANGE COMMISSION</AGENCY>
                <DEPDOC>[Investment Company Act Release No. 35189; File No. 812-15535]</DEPDOC>
                <SUBJECT>Monachil Credit Income Fund, et al.</SUBJECT>
                <DATE>May 8, 2024.</DATE>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Securities and Exchange Commission (“Commission” or “SEC”).</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <P>
                    Notice of application for an order (“Order”) under sections 17(d) and 57(i) of the Investment Company Act of 1940 (the “Act”) and rule 17d-1 under the Act to permit certain joint transactions 
                    <PRTPAGE P="42010"/>
                    otherwise prohibited by sections 17(d) and 57(a)(4) of the Act and rule 17d-1 under the Act.
                </P>
                <P>
                    <E T="03">Summary of Application:</E>
                     Applicants request an order to permit certain business development companies (“BDCs”) and closed-end management investment companies to co-invest in portfolio companies with each other and with certain affiliated investment entities.
                </P>
                <P>
                    <E T="03">Applicants:</E>
                     Monachil Credit Income Fund, Monachil Capital Partners LP, Monachil Credit Partners Master Fund I LP, and Monachil Credit Partners Master Fund II LP.
                </P>
                <P>
                    <E T="03">Filing Dates:</E>
                     The application was filed on December 20, 2023 and amended on March 19, 2024, and April 25, 2024.
                </P>
                <P>
                    <E T="03">Hearing or Notification of Hearing:</E>
                     An order granting the requested relief will be issued unless the Commission orders a hearing. Interested persons may request a hearing on any application by emailing the SEC's Secretary at 
                    <E T="03">Secretarys-Office@sec.gov</E>
                     and serving the Applicants with a copy of the request by email, if an email address is listed for the relevant Applicant below, or personally or by mail, if a physical address is listed for the relevant Applicant below. Hearing requests should be received by the Commission by 5:30 p.m. on June 3, 2024, and should be accompanied by proof of service on applicants, in the form of an affidavit or, for lawyers, a certificate of service. Pursuant to rule 0-5 under the Act, hearing requests should state the nature of the writer's interest, any facts bearing upon the desirability of a hearing on the matter, the reason for the request, and the issues contested. Persons who wish to be notified of a hearing may request notification by emailing the Commission's Secretary at 
                    <E T="03">Secretarys-Office@sec.gov</E>
                    .
                </P>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        The Commission: 
                        <E T="03">Secretarys-Office@sec.gov.</E>
                         Applicants: David Baum, Alston &amp; Bird LLP, at 
                        <E T="03">david.baum@alston.com.</E>
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Jill Ehrlich, Senior Counsel, or Lisa Reid Ragen, Branch Chief, at (202) 551-6825 (Division of Investment Management, Chief Counsel's Office).</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    For Applicants' representations, legal analysis, and conditions, please refer to Applicants' second amended and restated application, dated April 25, 2024, which may be obtained via the Commission's website by searching for the file number at the top of this document, or for an Applicant using the Company name search field, on the SEC's EDGAR system. The SEC's EDGAR system may be searched at, 
                    <E T="03">http://www.sec.gov/edgar/searchedgar/legacy/companysearch.html.</E>
                     You may also call the SEC's Public Reference Room at (202) 551-8090.
                </P>
                <P>For the Commission, by the Division of Investment Management, under delegated authority.</P>
                <SIG>
                    <NAME>Sherry R. Haywood,</NAME>
                    <TITLE>Assistant Secretary.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10422 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 8011-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">SMALL BUSINESS ADMINISTRATION</AGENCY>
                <DEPDOC>[Disaster Declaration #20303 and #20304; OKLAHOMA Disaster Number OK-20001]</DEPDOC>
                <SUBJECT>Presidential Declaration Amendment of a Major Disaster for the State of Oklahoma</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Small Business Administration.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Amendment 2.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>This is an amendment of the Presidential declaration of a major disaster for the State of Oklahoma (FEMA-4776-DR), dated 04/30/2024.</P>
                    <P>
                        <E T="03">Incident:</E>
                         Severe Storms, Straight-line Winds, Tornadoes, and Flooding.
                    </P>
                    <P>
                        <E T="03">Incident Period:</E>
                         04/25/2024 and continuing.
                    </P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Issued on 05/07/2024.</P>
                    <P>
                        <E T="03">Physical Loan Application Deadline Date:</E>
                         07/01/2024.
                    </P>
                    <P>
                        <E T="03">Economic Injury (EIDL) Loan Application Deadline Date:</E>
                         01/30/2025.
                    </P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        <E T="03">Visit the MySBA Loan Portal at https://lending.sba.gov</E>
                         to apply for a disaster assistance loan.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Alan Escobar, Office of Disaster Recovery &amp; Resilience, U.S. Small Business Administration, 409 3rd Street SW, Suite 6050, Washington, DC 20416, (202) 205-6734.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The notice of the President's major disaster declaration for the State of Oklahoma, dated 04/30/2024, is hereby amended to include the following areas as adversely affected by the disaster:</P>
                <FP SOURCE="FP-2">
                    <E T="03">Primary Counties (Physical Damage and Economic Injury Loans):</E>
                     Okmulgee.
                </FP>
                <FP SOURCE="FP-2">
                    <E T="03">Contiguous Counties (Economic Injury Loans Only):</E>
                     Oklahoma: Creek, Muskogee, Tulsa, Wagoner.
                </FP>
                <P>All other information in the original declaration remains unchanged.</P>
                <EXTRACT>
                    <FP>(Catalog of Federal Domestic Assistance Number 59008)</FP>
                </EXTRACT>
                <SIG>
                    <NAME>Francisco Sánchez, Jr.,</NAME>
                    <TITLE>Associate Administrator, Office of Disaster Recovery &amp; Resilience.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10436 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 8026-09-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF STATE</AGENCY>
                <DEPDOC>[Public Notice: 12397]</DEPDOC>
                <SUBJECT>Notice of Department of State Sanctions Actions</SUBJECT>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The U.S. Department of State's Office of Economic Sanctions Policy and Implementation (SPI) is publishing the name of one person who has been removed from the List of Specially Designated Nationals and Blocked Persons (SDN List) maintained by the Office of Foreign Assets Control (OFAC) and is consequently no longer subject to the prohibitions imposed pursuant to the Executive Order, “Blocking Property With Respect To Specified Harmful Foreign Activities of the Government of the Russian Federation.”</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The action described in this notice was effective on January 31, 2024.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Aaron P. Forsberg, Director, Office of Economic Sanctions Policy and Implementation, Bureau of Economic and Business Affairs, Department of State, Washington, DC 20520, tel.: (202) 647-7677, email: 
                        <E T="03">ForsbergAP@state.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">Electronic Availability</HD>
                <P>
                    The SDN List and additional information concerning OFAC sanctions programs are available from OFAC's website at 
                    <E T="03">http://www.treasury.gov/ofac.</E>
                </P>
                <HD SOURCE="HD1">Notice of Department of State Action</HD>
                <P>On January 31, 2024, pursuant to a decision by the Department of State, OFAC removed from the SDN List the person listed below, who was subject to prohibitions imposed pursuant to E.O. 14024 of April 15, 2021.</P>
                <GPH SPAN="3" DEEP="149">
                    <PRTPAGE P="42011"/>
                    <GID>EN14MY24.119</GID>
                </GPH>
                <SIG>
                    <NAME>Amy E. Holman,</NAME>
                    <TITLE>Principal Deputy Assistant Secretary, Bureau of Economic and Business Affairs, Department of State.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10509 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4710-07-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF STATE</AGENCY>
                <DEPDOC>[Public Notice 12403]</DEPDOC>
                <SUBJECT>60-Day Notice of Proposed Information Collection: Recording, Reporting and Data Collection Requirements—Student and Exchange Visitor Information System (SEVIS)</SUBJECT>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of request for public comment.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Department of State is seeking Office of Management and Budget (OMB) approval for the information collection described below. In accordance with the Paperwork Reduction Act of 1995, we are requesting comments on this collection from all interested individuals and organizations. The purpose of this notice is to allow 60 days for public comment preceding submission of the collection to OMB.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>
                        The Department will accept comments from the public up to 
                        <E T="03">July 15, 2024.</E>
                    </P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>You may submit comments by any of the following methods:</P>
                    <P>
                        • 
                        <E T="03">Web:</E>
                         Persons with access to the internet may comment on this notice by going to 
                        <E T="03">www.Regulations.gov.</E>
                         You can search for the document by entering “Docket Number: DOS-2024-0017” in the Search field. Then click the “Comment Now” button and complete the comment form.
                    </P>
                    <P>
                        • 
                        <E T="03">Email: jexchanges@state.gov.</E>
                    </P>
                    <P>
                        • 
                        <E T="03">Regular Mail:</E>
                         Send written comments to: U.S. Department of State, Private Sector Exchange Directorate (ECA/EC), SA-5, 2200 C Street NW, Washington, DC 20522-0505, ATTN: 
                        <E T="04">Federal Register</E>
                         Notice Response.
                    </P>
                    <P>You must include the DS form number (if applicable), information collection title, and the OMB control number in any correspondence.</P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Direct requests for additional information regarding the collection listed in this notice, including requests to Private Sector Exchange Directorate (ECA/EC), U.S Department of State, SA-5, 2200 C Street NW, Washington, DC 20522-0505, ATTN: 
                        <E T="04">Federal Register</E>
                         Notice Response, Jennifer Nupp, at phone: (202) 826-4364, or via email: 
                        <E T="03">jexchanges@state.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P/>
                <P>
                    • 
                    <E T="03">Title of Information Collection:</E>
                     Recording, Reporting, and Data Collection Requirements—Student and Exchange Visitor Information System (SEVIS).
                </P>
                <P>
                    • 
                    <E T="03">OMB Control Number:</E>
                     1405-0147.
                </P>
                <P>
                    • 
                    <E T="03">Type of Request:</E>
                     Reinstatement of a previously approved collection.
                </P>
                <P>
                    • 
                    <E T="03">Originating Office:</E>
                     Bureau of Educational and Cultural Affairs (ECA/EC).
                </P>
                <P>
                    • 
                    <E T="03">Form Number:</E>
                     DS-3036, DS-3037, DS-7000.
                </P>
                <P>
                    • 
                    <E T="03">Respondents:</E>
                     U.S. government and public and private organizations wishing to become Department of State designated sponsors authorized to conduct exchange visitor programs, and Department of State designated sponsors and exchange visitors and hosts.
                </P>
                <P>
                    • 
                    <E T="03">Estimated Number of Respondents:</E>
                     186,910 (DS-3036—60); (DS-3037—1,450); (DS-7000—185,400).
                </P>
                <P>
                    • 
                    <E T="03">Estimated Number of Responses:</E>
                     2,001,524 (DS-3036—60; DS-3037—2,900; DS-7000—1,998,564 (1,977,588 for Non-SEVIS and 20,976 for SEVIS).
                </P>
                <P>
                    • 
                    <E T="03">Average Time Per Response:</E>
                     DS-3036—8 hours; DS-3037—20 minutes; DS-7000—45 minutes.
                </P>
                <P>
                    • 
                    <E T="03">Total Estimated Burden Time:</E>
                     1,988,286 hours (DS-3036—480 hours; DS-3037 943 hours; DS-7000—1,986,863).
                </P>
                <P>
                    • 
                    <E T="03">Frequency:</E>
                     On occasion.
                </P>
                <P>
                    • 
                    <E T="03">Obligation to Respond:</E>
                     Required to Obtain or Retain a Benefit.
                </P>
                <P>We are soliciting public comments to permit the Department to:</P>
                <P>• Evaluate whether the proposed information collection is necessary for the proper functions of the Department.</P>
                <P>• Evaluate the accuracy of our estimate of the time and cost burden for this proposed collection, including the validity of the methodology and assumptions used.</P>
                <P>• Enhance the quality, utility, and clarity of the information to be collected.</P>
                <P>• Minimize the reporting burden on those who are to respond, including the use of automated collection techniques or other forms of information technology.</P>
                <P>Please note that comments submitted in response to this Notice are public record. Before including any detailed personal information, you should be aware that your comments as submitted, including your personal information, will be available for public review.</P>
                <HD SOURCE="HD1">Abstract of Proposed Collection</HD>
                <P>
                    The collection contains information collected by the Bureau of Educational and Cultural Affairs in administering the Exchange Visitor Program (J-Visa) under the provisions of the Mutual Educational and Cultural Exchange Act, as amended (22 U.S.C. 2451, 
                    <E T="03">et seq.</E>
                </P>
                <HD SOURCE="HD1">Methodology</HD>
                <P>
                    Information will be collected through mail or electronic submission. Access to Forms DS-3036 and DS-3037 are found in the Student and Exchange Visitor Information System (SEVIS). Form DS-7000 is an internal spreadsheet that summarizes the burden resulting from 
                    <PRTPAGE P="42012"/>
                    requirements of the Exchange Visitor Program rules in 22 CFR part 62.
                </P>
                <SIG>
                    <NAME>Rebecca Pasini,</NAME>
                    <TITLE>Deputy Assistant Secretary, Bureau of Educational and Cultural Affairs.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10487 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4710-05-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF STATE</AGENCY>
                <DEPDOC>[Public Notice: 12401]</DEPDOC>
                <SUBJECT>Notice of Department of State Sanctions Actions Pursuant to the Executive Order Regarding Blocking Property With Respect to Specified Harmful Foreign Activities of the Government of the Russian Federation</SUBJECT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Department of State is publishing the names of one or more persons that have been placed on the Department of Treasury's List of Specially Designated Nationals and Blocked Persons (SDN List) administered by the Office of Foreign Asset Control (OFAC) based on the Department of State's determination, in consultation with other departments, as appropriate, that one or more applicable legal criteria of the Executive order regarding blocking property with respect to specified harmful foreign activities of the Government of the Russian Federation were satisfied. All property and interests in property subject to U.S. jurisdiction of these persons are blocked, and U.S. persons are generally prohibited from engaging in transactions with them.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>
                        See 
                        <E T="02">SUPPLEMENTARY INFORMATION</E>
                         section for applicable date(s).
                    </P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Aaron P. Forsberg, Director, Office of Economic Sanctions Policy and Implementation, Bureau of Economic and Business Affairs, Department of State, Washington, DC 20520, tel.: (202) 647 7677, email: 
                        <E T="03">ForsbergAP@state.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">Electronic Availability</HD>
                <P>
                    The SDN List and additional information concerning sanctions programs are available on OFAC's website, 
                    <E T="03">https://ofac.treasury.gov/sanctions-programs-and-country-information/russian-harmful-foreign-activities-sanctions.</E>
                </P>
                <HD SOURCE="HD1">Notice of Department of State Actions</HD>
                <P>On July 20, 2023, OFAC removed from the SDN List the two persons listed below, who were subject to prohibitions imposed pursuant to E.O. 14024 of April 15, 2021.</P>
                <BILCOD>BILLING CODE 4210-07-P</BILCOD>
                <GPH SPAN="3" DEEP="508">
                    <PRTPAGE P="42013"/>
                    <GID>EN14MY24.120</GID>
                </GPH>
                <GPH SPAN="3" DEEP="563">
                    <PRTPAGE P="42014"/>
                    <GID>EN14MY24.121</GID>
                </GPH>
                <GPH SPAN="3" DEEP="593">
                    <PRTPAGE P="42015"/>
                    <GID>EN14MY24.122</GID>
                </GPH>
                <GPH SPAN="3" DEEP="618">
                    <PRTPAGE P="42016"/>
                    <GID>EN14MY24.123</GID>
                </GPH>
                <GPH SPAN="3" DEEP="563">
                    <PRTPAGE P="42017"/>
                    <GID>EN14MY24.124</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42018"/>
                    <GID>EN14MY24.125</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42019"/>
                    <GID>EN14MY24.126</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42020"/>
                    <GID>EN14MY24.127</GID>
                </GPH>
                <GPH SPAN="3" DEEP="563">
                    <PRTPAGE P="42021"/>
                    <GID>EN14MY24.128</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42022"/>
                    <GID>EN14MY24.129</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42023"/>
                    <GID>EN14MY24.130</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42024"/>
                    <GID>EN14MY24.131</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42025"/>
                    <GID>EN14MY24.132</GID>
                </GPH>
                <GPH SPAN="3" DEEP="618">
                    <PRTPAGE P="42026"/>
                    <GID>EN14MY24.133</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42027"/>
                    <GID>EN14MY24.134</GID>
                </GPH>
                <GPH SPAN="3" DEEP="563">
                    <PRTPAGE P="42028"/>
                    <GID>EN14MY24.135</GID>
                </GPH>
                <GPH SPAN="3" DEEP="618">
                    <PRTPAGE P="42029"/>
                    <GID>EN14MY24.136</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42030"/>
                    <GID>EN14MY24.137</GID>
                </GPH>
                <GPH SPAN="3" DEEP="563">
                    <PRTPAGE P="42031"/>
                    <GID>EN14MY24.138</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42032"/>
                    <GID>EN14MY24.139</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42033"/>
                    <GID>EN14MY24.140</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42034"/>
                    <GID>EN14MY24.141</GID>
                </GPH>
                <GPH SPAN="3" DEEP="535">
                    <PRTPAGE P="42035"/>
                    <GID>EN14MY24.142</GID>
                </GPH>
                <GPH SPAN="3" DEEP="535">
                    <PRTPAGE P="42036"/>
                    <GID>EN14MY24.143</GID>
                </GPH>
                <GPH SPAN="3" DEEP="598">
                    <PRTPAGE P="42037"/>
                    <GID>EN14MY24.144</GID>
                </GPH>
                <GPH SPAN="3" DEEP="609">
                    <PRTPAGE P="42038"/>
                    <GID>EN14MY24.145</GID>
                </GPH>
                <GPH SPAN="3" DEEP="626">
                    <PRTPAGE P="42039"/>
                    <GID>EN14MY24.146</GID>
                </GPH>
                <GPH SPAN="3" DEEP="563">
                    <PRTPAGE P="42040"/>
                    <GID>EN14MY24.147</GID>
                </GPH>
                <GPH SPAN="3" DEEP="563">
                    <PRTPAGE P="42041"/>
                    <GID>EN14MY24.148</GID>
                </GPH>
                <GPH SPAN="3" DEEP="618">
                    <PRTPAGE P="42042"/>
                    <GID>EN14MY24.149</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42043"/>
                    <GID>EN14MY24.150</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42044"/>
                    <GID>EN14MY24.151</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42045"/>
                    <GID>EN14MY24.152</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42046"/>
                    <GID>EN14MY24.153</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42047"/>
                    <GID>EN14MY24.154</GID>
                </GPH>
                <GPH SPAN="3" DEEP="590">
                    <PRTPAGE P="42048"/>
                    <GID>EN14MY24.155</GID>
                </GPH>
                <GPH SPAN="3" DEEP="480">
                    <PRTPAGE P="42049"/>
                    <GID>EN14MY24.156</GID>
                </GPH>
                <SIG>
                    <NAME>Amy E. Holman,</NAME>
                    <TITLE>Principal Deputy Assistant Secretary, Bureau of Economic and Business Affairs, Department of State.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10510 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4710-07-C</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">SURFACE TRANSPORTATION BOARD</AGENCY>
                <DEPDOC>[Docket No. EP 526 (Sub No. 21)]</DEPDOC>
                <SUBJECT>Notice of Railroad-Shipper Transportation Advisory Council Vacancy</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Surface Transportation Board (Board).</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of vacancy on the Railroad-Shipper Transportation Advisory Council (RSTAC) and solicitation of nominations.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Board hereby gives notice of a vacancy on RSTAC for a small railroad representative. The Board seeks nominations for candidates to fill this vacancy.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Nominations are due on June 13, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Nominations may be submitted via e-filing on the Board's website at 
                        <E T="03">www.stb.gov.</E>
                         Submissions will be posted to the Board's website under Docket No. EP 526 (Sub-No. 21).
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Gabriel Meyer at (202) 245-0150. If you require an accommodation under the Americans with Disabilities Act, please call (202) 245-0245.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>
                    The Board, created in 1996 to take over many of the functions previously performed by the Interstate Commerce Commission, exercises broad authority over transportation by rail carriers, including regulation of railroad rates and service (49 U.S.C. 10701-47, 11101-24), the construction, acquisition, operation, and abandonment of rail lines (49 U.S.C. 10901-07), as well as railroad line sales, consolidations, mergers, and common 
                    <PRTPAGE P="42050"/>
                    control arrangements (49 U.S.C. 10902, 11323-27).
                </P>
                <P>The ICC Termination Act of 1995 (ICCTA), enacted on December 29, 1995, established RSTAC to advise the Board's Chair; the Secretary of Transportation; the Committee on Commerce, Science, and Transportation of the Senate; and the Committee on Transportation and Infrastructure of the House of Representatives with respect to rail transportation policy issues RSTAC considers significant. RSTAC focuses on issues of importance to small shippers and small railroads, including car supply, rates, competition, and procedures for addressing claims.</P>
                <P>ICCTA instructs RSTAC to endeavor to develop private sector mechanisms to prevent, or identify and address, obstacles to the most effective and efficient transportation system practicable. The members of RSTAC also prepare an annual report concerning RSTAC's activities. RSTAC is not subject to the Federal Advisory Committee Act.</P>
                <P>RSTAC's 15 appointed members consist of representatives of small and large shippers, and small and large railroads. These members are appointed by the Chair. In addition, members of the Board and the Secretary of Transportation serve as ex officio members. Of the 15 appointed members, nine are voting members and are appointed from senior executive officers of organizations engaged in the railroad and rail shipping industries. At least four of the voting members must be representatives of small shippers as determined by the Chair, and at least four of the voting members must be representatives of Class II or III railroads. The remaining voting member has traditionally been an at-large representative. The other six members—three representing Class I railroads and three representing large shipper organizations—serve in a nonvoting, advisory capacity, but may participate in RSTAC deliberations.</P>
                <P>Meetings of RSTAC are required by statute to be held at least semi-annually. RSTAC typically holds meetings quarterly at the Board's headquarters in Washington, DC, although some meetings are held virtually or in other locations.</P>
                <P>The members of RSTAC receive no compensation for their services and are required to provide for the expenses incidental to their service, including travel expenses. Currently, RSTAC members have elected to submit annual dues to pay for RSTAC expenses.</P>
                <P>
                    RSTAC members must be citizens of the United States and represent as broadly as practicable the various segments of the railroad and rail shipper industries. They may not be full-time employees of the United States Government. According to revised guidance issued by the Office of Management and Budget, it is permissible for federally registered lobbyists to serve on advisory committees, such as RSTAC, as long as they do so in a representative capacity rather than an individual capacity. 
                    <E T="03">See Revised Guidance on Appointment of Lobbyists to Fed. Advisory Comms., Bds., &amp; Comm'ns,</E>
                     79 FR 47482 (Aug. 13, 2014). Members of RSTAC are appointed to serve in a representative capacity.
                </P>
                <P>Each RSTAC member is appointed for a term of three years. No member will be eligible to serve in excess of two consecutive terms. However, a member may serve after the expiration of his or her term until a successor has taken office.</P>
                <P>Due to the expiration of an RSTAC member's term, a vacancy exists for a small railroad representative. Nominations for candidates to fill the vacancy should be submitted in letter form, identifying the name of the candidate, providing a summary of why the candidate is qualified to serve on RSTAC, and containing representations that the candidate is willing to serve as an RSTAC member effective immediately upon appointment. Candidates may nominate themselves. The Chair is committed to having a committee reflecting diverse communities and viewpoints and strongly encourages the nomination of candidates from diverse backgrounds. RSTAC candidate nominations should be filed with the Board by June 13, 2024. Members selected to serve on RSTAC are chosen at the discretion of the Board's Chair.</P>
                <P>
                    Please note that submissions will be posted on the Board's website under Docket No. EP 526 (Sub-No. 21) and can also be obtained by contacting the Office of Public Assistance, Governmental Affairs, and Compliance at 
                    <E T="03">RCPA@stb.gov</E>
                     or (202) 245-0238.
                </P>
                <P>
                    <E T="03">Authority:</E>
                     49 U.S.C. 1325.
                </P>
                <SIG>
                    <DATED>Decided: May 8, 2024.</DATED>
                    <P>By the Board, Mai T. Dinh, Director, Office of Proceedings.</P>
                    <NAME>Tammy Lowery,</NAME>
                    <TITLE>Clearance Clerk.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10493 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4915-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">SUSQUEHANNA RIVER BASIN COMMISSION</AGENCY>
                <SUBJECT>Grandfathering (GF) Registration Notice</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Susquehanna River Basin Commission.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>
                        This notice lists Grandfathering Registration for projects by the Susquehanna River Basin Commission during the period set forth in 
                        <E T="02">DATES</E>
                        .
                    </P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>April 1-30, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>Susquehanna River Basin Commission, 4423 North Front Street, Harrisburg, PA 17110-1788.</P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Jason E. Oyler, General Counsel and Secretary to the Commission, telephone: (717) 238-0423, ext. 1312; fax: (717) 238-2436; email: 
                        <E T="03">joyler@srbc.gov</E>
                         . Regular mail inquiries may be sent to the above address.
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>This notice lists GF Registration for projects described below, pursuant to 18 CFR part 806, subpart E, for the time period specified above:</P>
                <P>1. H. H. Knoebel Sons, Inc. dba Knoebels Amusement Resort, GF Certificate No. GF 202404277, Ralpho Township, Northumberland County, and Cleveland Township, Columbia County, Pennsylvania; South Branch Roaring Creek and consumptive use; Issue Date: April 16, 2024.</P>
                <P>
                    <E T="03">Authority:</E>
                     Public Law 91-575, 84 Stat. 1509 
                    <E T="03">et seq.,</E>
                     18 CFR parts 806 and 808.
                </P>
                <SIG>
                    <DATED>Dated: May 9, 2024.</DATED>
                    <NAME>Jason E. Oyler,</NAME>
                    <TITLE>General Counsel and Secretary to the Commission.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10517 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 7040-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">SUSQUEHANNA RIVER BASIN COMMISSION</AGENCY>
                <SUBJECT>Projects Approved for Consumptive Uses of Water</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Susquehanna River Basin Commission.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>
                        This notice lists Approvals by Rule for projects by the Susquehanna River Basin Commission during the period set forth in 
                        <E T="02">DATES</E>
                        .
                    </P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>April 1-30, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>Susquehanna River Basin Commission, 4423 North Front Street, Harrisburg, PA 17110-1788.</P>
                </ADD>
                <FURINF>
                    <PRTPAGE P="42051"/>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Jason E. Oyler, General Counsel and Secretary to the Commission, telephone: (717) 238-0423, ext. 1312; fax: (717) 238-2436; email: 
                        <E T="03">joyler@srbc.gov.</E>
                         Regular mail inquiries may be sent to the above address.
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>This notice lists the projects described below, receiving approval for the consumptive use of water pursuant to the Commission's approval by rule process set forth in 18 CFR 806.22 (e) and 18 CFR 806.22 (f) for the period specified above.</P>
                <HD SOURCE="HD1">Water Source Approval—Issued Under 18 CFR 806.22(e)</HD>
                <P>1. The Hershey Company—Hershey Plant (Reese Avenue); ABR-202404001; Derry Township, Dauphin County, Pa.; Consumptive Use of Up to 0.0500 mgd; Approval Date: April 2, 2024.</P>
                <P>2. Penn State Health Holy Spirit Medical Center—Holy Spirit Medical Center; ABR-202404002; East Pennsboro Township, Cumberland County, Pa.; Consumptive Use of Up to 0.2070 mgd; Approval Date: April 2, 2024.</P>
                <P>3. Church &amp; Dwight Co., Inc.—Davies Facility; ABR-202404003; Jackson Township, York County, Pa.; Consumptive Use of Up to 0.9990 mgd; Approval Date: April 18, 2024.</P>
                <HD SOURCE="HD1">Water Source Approval—Issued Under 18 CFR 806.22(f)</HD>
                <P>1. Coterra Energy Inc.; Pad ID: FrystakC P2; ABR-202404004; Bridgewater Township, Susquehanna County, Pa.; Consumptive Use of Up to 5.0000 mgd; Approval Date: April 15, 2024.</P>
                <P>2. RENEWAL—Chesapeake Appalachia, LLC; Pad ID: Garrison; ABR-201403012.R2; Washington Township, Wyoming County, Pa.; Consumptive Use of Up to 7.5000 mgd; Approval Date: April 15, 2024.</P>
                <P>3. RENEWAL—Chesapeake Appalachia, LLC; Pad ID: Leh Drilling Pad #1; ABR-201204002.R2; Burlington Township, Bradford County, Pa.; Consumptive Use of Up to 7.5000 mgd; Approval Date: April 15, 2024.</P>
                <P>4. RENEWAL—Chesapeake Appalachia, LLC; Pad ID: TA; ABR-201403011.R2; Colley Township, Sullivan County, Pa.; Consumptive Use of Up to 7.5000 mgd; Approval Date: April 15, 2024.</P>
                <P>5. RENEWAL—EQT ARO LLC; Pad ID: COP Tract 231 (1000); ABR-20090406.R3; Snow Shoe Township, Centre County, Pa.; Consumptive Use of Up to 4.0000 mgd; Approval Date: April 15, 2024.</P>
                <P>6. RENEWAL—Pennsylvania General Energy Company, LLC; Pad ID: SGL 75 Pad F; ABR-201403005.R2; McHenry Township, Lycoming County, Pa.; Consumptive Use of Up to 2.5000 mgd; Approval Date: April 15, 2024.</P>
                <P>7. RENEWAL—Seneca Resources Company, LLC; Pad ID: PHC 3H; ABR-20090424.R3; Lawrence Township, Clearfield County, Pa.; Consumptive Use of Up to 4.0000 mgd; Approval Date: April 15, 2024.</P>
                <P>8. RENEWAL—SWN Production Company, LLC; Pad ID: Fiondi—1; ABR-20090404.R3; Middletown Township, Susquehanna County, Pa.; Consumptive Use of Up to 4.9990 mgd; Approval Date: April 15, 2024.</P>
                <P>9. RENEWAL—SWN Production Company, LLC; Pad ID: Holbrook # 1; ABR-20090402.R3; Bridgewater Township, Susquehanna County, Pa.; Consumptive Use of Up to 4.9990 mgd; Approval Date: April 15, 2024.</P>
                <P>10. RENEWAL—SWN Production Company, LLC; Pad ID: Turner—1; ABR-20090403.R3; Liberty Township, Susquehanna County, Pa.; Consumptive Use of Up to 4.9990 mgd; Approval Date: April 15, 2024.</P>
                <P>11. RENEWAL—SWN Production Company, LLC; Pad ID: Webster—1; ABR-20090401.R3; Franklin Township, Susquehanna County, Pa.; Consumptive Use of Up to 2.9990 mgd; Approval Date: April 15, 2024.</P>
                <P>12. RENEWAL—Chesapeake Appalachia, LLC; Pad ID: Manning; ABR-201204009.R2; Cherry Township, Sullivan County, Pa.; Consumptive Use of Up to 7.5000 mgd; Approval Date: April 25, 2024.</P>
                <P>13. RENEWAL—Seneca Resources Company, LLC; Pad ID: Edkin 499; ABR-201304018.R2; Sullivan Township, Tioga County, Pa.; Consumptive Use of Up to 4.0000 mgd; Approval Date: April 25, 2024.</P>
                <P>14. RENEWAL—Seneca Resources Company, LLC; Pad ID: Flack 502; ABR-201304014.R2; Sullivan Township, Tioga County, Pa.; Consumptive Use of Up to 4.0000 mgd; Approval Date: April 25, 2024.</P>
                <P>15. RENEWAL—Seneca Resources Company, LLC; Pad ID: Hepler 235; ABR-201204008.R2; Sullivan Township, Tioga County, Pa.; Consumptive Use of Up to 4.0000 mgd; Approval Date: April 25, 2024.</P>
                <P>16. RENEWAL—Chesapeake Appalachia, LLC; Pad ID: I. Harvey Drilling Pad; ABR-201404006.R2; Elkland Township, Sullivan County, Pa.; Consumptive Use of Up to 7.5000 mgd; Approval Date: April 30, 2024.</P>
                <P>17. RENEWAL—Chesapeake Appalachia, LLC; Pad ID: SGL 12 D DRILLING PAD; ABR-201704002.R1; Leroy Township, Bradford County, Pa.; Consumptive Use of Up to 7.5000 mgd; Approval Date: April 30, 2024.</P>
                <P>18. RENEWAL—Pennsylvania General Energy Company, LLC; Pad ID: SGL75 Pad A; ABR-201404007.R2; McHenry Township, Lycoming County, Pa.; Consumptive Use of Up to 2.5000 mgd; Approval Date: April 30, 2024.</P>
                <P>
                    <E T="03">Authority:</E>
                     Public Law 91-575, 84 Stat. 1509 
                    <E T="03">et seq.,</E>
                     18 CFR parts 806 and 808.
                </P>
                <SIG>
                    <DATED>Dated: May 9, 2024.</DATED>
                    <NAME>Jason E. Oyler,</NAME>
                    <TITLE>General Counsel and Secretary to the Commission.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10519 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 7040-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">SUSQUEHANNA RIVER BASIN COMMISSION</AGENCY>
                <SUBJECT>General Permit Notice</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Susquehanna River Basin Commission.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>
                        This notice lists General Permits issued for projects by the Susquehanna River Basin Commission during the period set forth in 
                        <E T="02">DATES</E>
                        .
                    </P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>April 1-30, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>Susquehanna River Basin Commission, 4423 North Front Street, Harrisburg, PA 17110-1788.</P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Jason E. Oyler, General Counsel and Secretary to the Commission, telephone: (717) 238-0423, ext. 1312; fax: (717) 238-2436; email: 
                        <E T="03">joyler@srbc.gov</E>
                         . Regular mail inquiries may be sent to the above address.
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>This notice lists General Permits for projects described below, pursuant to 18 CFR part 806.17, for the time period specified above:</P>
                <P>1. International Business Machines Corporation—Endicott Facility, General Permit Approval of Coverage No. GP-01-20240405, Village of Endicott, Broome County, NY; groundwater remediation system withdrawal approved up to 0.300 mgd (30-day average); Approval Date: April 23, 2024.</P>
                <P>
                    <E T="03">Authority:</E>
                     Public Law 91-575, 84 Stat. 1509 
                    <E T="03">et seq.,</E>
                     18 CFR parts 806 and 808.
                </P>
                <SIG>
                    <DATED>Dated: May 9, 2024.</DATED>
                    <NAME>Jason E. Oyler,</NAME>
                    <TITLE>General Counsel and Secretary to the Commission.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10516 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 7040-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <PRTPAGE P="42052"/>
                <AGENCY TYPE="S">SUSQUEHANNA RIVER BASIN COMMISSION</AGENCY>
                <SUBJECT>Commission Meeting</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Susquehanna River Basin Commission.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>
                        The Susquehanna River Basin Commission will conduct its regular business meeting on June 13, 2024 in Harrisburg, Pennsylvania. Details concerning the matters to be addressed at the business meeting are contained in the 
                        <E T="02">Supplementary Information</E>
                         section of this notice. Also the Commission published a document in the 
                        <E T="04">Federal Register</E>
                         on April 9, 2024, concerning its public hearing on May 2, 2024, in Harrisburg, Pennsylvania.
                    </P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>The meeting will be held on Thursday, June 13, 2024, at 9 a.m.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>This public meeting will be conducted in person and digitally from the Susquehanna River Basin Commission,4423 N Front Street, Harrisburg, Pennsylvania.</P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Jason E. Oyler, General Counsel and Secretary to the Commission, telephone: 717-238-0423; fax: 717-238-2436.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The business meeting will include actions or presentations on the following items: (1) election of Commission officers for FY2025; (2) reconciliation of FY 2025 budget; (3) approval of contracts, grants and agreements; (4) action on proposed rulemaking for agency procurement, bid protest procedures and other changes to part 801, and a draft policy entitled “SRBC Procurement Procedures”; (5) adoption of the proposed 2025-2027 Water Resources Program; and (6) actions on 19 regulatory program projects.</P>
                <P>
                    This agenda is complete at the time of issuance, but other items may be added, and some stricken without further notice. The listing of an item on the agenda does not necessarily mean that the Commission will take final action on it at this meeting. When the Commission does take final action, notice of these actions will be published in the 
                    <E T="04">Federal Register</E>
                     after the meeting. Any actions specific to projects will also be provided in writing directly to project sponsors.
                </P>
                <P>
                    The meeting will be conducted both in person at the Susquehanna River Basin Commission, 4423 N Front Street, Harrisburg, Pennsylvania and digitally. The public is invited to attend the Commission's business meeting. You can access the Business Meeting remotely via Zoom: 
                    <E T="03">https://us02web.zoom.us/j/89292000071?pwd=S1E2Qi9QNHUyTkhjY3ZoRUJJeXpqUT09</E>
                     Meeting ID 892 9200 0071; Passcode: SRBC4423! or via telephone: 305-224-1968 or 309-205-3325; Meeting ID 892 9200 0071.
                </P>
                <P>
                    Written comments pertaining to items on the agenda at the business meeting may be mailed to the Susquehanna River Basin Commission, 4423 North Front Street, Harrisburg, Pennsylvania 17110-1788, or submitted electronically at the link Business Meeting Comments. The draft rulemaking and policy can be viewed on the Commission's website at 
                    <E T="03">https://www.srbc.gov/meeting-comment/default.aspx?type=19&amp;cat=43.</E>
                     Comments are due to the Commission for all items on the business meeting agenda on or before June 10, 2024. Comments will not be accepted at the business meeting noticed herein.
                </P>
                <P>
                    <E T="03">Authority:</E>
                     Pub. L. 91-575, 84 Stat. 1509 
                    <E T="03">et seq.,</E>
                     18 CFR parts 806, 807, and 808.
                </P>
                <SIG>
                    <DATED>Dated: May 9, 2024.</DATED>
                    <NAME>Jason E. Oyler,</NAME>
                    <TITLE>General Counsel and Secretary to the Commission.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10520 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 7040-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">OFFICE OF THE UNITED STATES TRADE REPRESENTATIVE</AGENCY>
                <DEPDOC>[Docket Number USTR-2024-0006]</DEPDOC>
                <SUBJECT>Request for Comments and Notice of Public Hearing Concerning the Annual Review of Country Eligibility for Benefits Under the African Growth and Opportunity Act for Calendar Year 2025</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Office of the United States Trade Representative.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Request for comments and notice of virtual public hearing.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Office of the United States Trade Representative (USTR) is announcing the initiation of the annual review of the eligibility of sub-Saharan African countries to receive the benefits of the African Growth and Opportunity Act (AGOA). The AGOA Implementation Subcommittee of the Trade Policy Staff Committee (AGOA TPSC Subcommittee) is requesting written public comments for this review and will conduct a virtual public hearing on this matter. In developing its recommendations on AGOA country eligibility for calendar year 2025, the AGOA TPSC Subcommittee will consider written comments, written testimony, and oral testimony.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P/>
                    <P>
                        <E T="03">June 6, 2024 at 11:59 p.m. EDT:</E>
                         Deadline for submission of pre hearing written comments, requests to testify, and written testimony, regarding the eligibility of countries to be designated as beneficiary sub-Saharan African countries.
                    </P>
                    <P>
                        <E T="03">June 27, 2024 at 10:00 a.m. EDT:</E>
                         The AGOA TPSC Subcommittee will convene a virtual public hearing to receive oral testimony related to sub-Saharan African countries' eligibility for AGOA benefits, via WebEx.
                    </P>
                    <P>
                        <E T="03">July 11, 2024 at 5:00 p.m. EDT:</E>
                         Deadline for submission of post hearing written comments, briefs, supplementary materials, and written statements related to the virtual public hearing.
                    </P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        The AGOA TPSC Subcommittee strongly prefers electronic submissions made through the Federal eRulemaking Portal: 
                        <E T="03">https://www.regulations.gov</E>
                         (
                        <E T="03">Regulations.gov</E>
                        ). Follow the instructions for submitting written comments and testimony and requests to testify in sections III and IV below, using Docket Number USTR-2024-0006. For alternatives to on-line submissions, please contact Jeremy Streatfeild, Director of African Affairs, Office of African Affairs, in advance of the relevant deadline at 
                        <E T="03">Jeremy.E.Streatfeild@ustr.eop.gov</E>
                         or (202) 395-8642.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Jeremy Streatfeild, Director of African Affairs, Office of African Affairs, at 
                        <E T="03">Jeremy.E.Streatfeild@ustr.eop.gov</E>
                         or (202) 395-8642.
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">I. Background</HD>
                <P>
                    AGOA (Title I of the Trade and Development Act of 2000, Public Law 106-200) (19 U.S.C. 2466a 
                    <E T="03">et seq.</E>
                    ), as amended, authorizes the President to designate sub-Saharan African countries as beneficiaries eligible for duty-free treatment for certain additional products not included for duty-free treatment under the Generalized System of Preferences (GSP) (Title V of the Trade Act of 1974 (19 U.S.C. 2461 
                    <E T="03">et seq.</E>
                    ) (1974 Act), as well as for the preferential treatment for certain textile and apparel articles. The President may designate a country as a beneficiary sub-Saharan African country eligible for AGOA benefits if he determines that the country meets the eligibility criteria set forth in section 104 of AGOA (19 U.S.C. 3703) and section 502 of the 1974 Act (19 U.S.C. 2462).
                </P>
                <P>
                    Section 104 of AGOA includes requirements that the country has established or is making continual 
                    <PRTPAGE P="42053"/>
                    progress toward establishing, among other things:
                </P>
                <FP SOURCE="FP-1">• a market-based economy</FP>
                <FP SOURCE="FP-1">• the rule of law</FP>
                <FP SOURCE="FP-1">• political pluralism</FP>
                <FP SOURCE="FP-1">• the right to due process</FP>
                <FP SOURCE="FP-1">• the elimination of barriers to U.S. trade and investment</FP>
                <FP SOURCE="FP-1">• economic policies to reduce poverty</FP>
                <FP SOURCE="FP-1">• a system to combat corruption and bribery</FP>
                <FP SOURCE="FP-1">• protection of internationally recognized worker rights</FP>
                <P>In addition, the country may not engage in activities that undermine U.S. national security or foreign policy interests or engage in gross violations of internationally recognized human rights. Section 502 of the 1974 Act provides for country eligibility criteria under GSP. For a complete list of the AGOA eligibility criteria and a list of the GSP criteria, see section 104 of the AGOA and section 502 of the 1974 Act.</P>
                <P>Section 506A of the 1974 Act requires the President to monitor and annually review the progress of each sub-Saharan African country in meeting the foregoing eligibility criteria in order to determine if a beneficiary sub-Saharan African country should continue to be eligible, and if a sub-Saharan African country that currently is not a beneficiary, should be designated as a beneficiary. If the President determines that a beneficiary sub-Saharan African country is not making continual progress in meeting the eligibility requirements, the President must terminate the designation of the country as a beneficiary sub-Saharan African country. The President also may withdraw, suspend or limit the application of duty-free treatment with respect to specific articles from a country if the President determines that it would be more effective in promoting compliance with AGOA eligibility requirements than terminating the designation of the country as a beneficiary sub-Saharan African country.</P>
                <P>For 2024, the President designated the following 32 countries as beneficiary sub-Saharan African countries:</P>
                <EXTRACT>
                    <FP SOURCE="FP-2">1. Angola</FP>
                    <FP SOURCE="FP-2">2. Benin</FP>
                    <FP SOURCE="FP-2">3. Botswana</FP>
                    <FP SOURCE="FP-2">4. Cabo Verde</FP>
                    <FP SOURCE="FP-2">5. Chad</FP>
                    <FP SOURCE="FP-2">6. Comoros</FP>
                    <FP SOURCE="FP-2">7. Democratic Republic of Congo</FP>
                    <FP SOURCE="FP-2">8. Republic of Congo</FP>
                    <FP SOURCE="FP-2">9. Cote d'Ivoire</FP>
                    <FP SOURCE="FP-2">10. Djibouti</FP>
                    <FP SOURCE="FP-2">11. Eswatini</FP>
                    <FP SOURCE="FP-2">12. The Gambia</FP>
                    <FP SOURCE="FP-2">13. Ghana</FP>
                    <FP SOURCE="FP-2">14. Guinea-Bissau</FP>
                    <FP SOURCE="FP-2">15. Kenya</FP>
                    <FP SOURCE="FP-2">16. Lesotho</FP>
                    <FP SOURCE="FP-2">17. Liberia</FP>
                    <FP SOURCE="FP-2">18. Madagascar</FP>
                    <FP SOURCE="FP-2">19. Malawi</FP>
                    <FP SOURCE="FP-2">20. Mauritania</FP>
                    <FP SOURCE="FP-2">21. Mauritius</FP>
                    <FP SOURCE="FP-2">22. Mozambique</FP>
                    <FP SOURCE="FP-2">23. Namibia</FP>
                    <FP SOURCE="FP-2">24. Nigeria</FP>
                    <FP SOURCE="FP-2">25. Rwanda (AGOA apparel benefits suspended effective July 31, 2018)</FP>
                    <FP SOURCE="FP-2">26. Sao Tome &amp; Principe</FP>
                    <FP SOURCE="FP-2">27. Senegal</FP>
                    <FP SOURCE="FP-2">28. Sierra Leone</FP>
                    <FP SOURCE="FP-2">29. South Africa</FP>
                    <FP SOURCE="FP-2">30. Tanzania</FP>
                    <FP SOURCE="FP-2">31. Togo</FP>
                    <FP SOURCE="FP-2">32. Zambia</FP>
                </EXTRACT>
                <P>The President did not designate the following sub-Saharan African countries as beneficiary sub-Saharan African countries for 2024:</P>
                <EXTRACT>
                    <FP SOURCE="FP-2">1. Burkina Faso</FP>
                    <FP SOURCE="FP-2">2. Burundi</FP>
                    <FP SOURCE="FP-2">3. Cameroon</FP>
                    <FP SOURCE="FP-2">4. Central African Republic</FP>
                    <FP SOURCE="FP-2">5. Equatorial Guinea (graduated from GSP)</FP>
                    <FP SOURCE="FP-2">6. Eritrea</FP>
                    <FP SOURCE="FP-2">7. Ethiopia</FP>
                    <FP SOURCE="FP-2">8. Gabon</FP>
                    <FP SOURCE="FP-2">9. Guinea</FP>
                    <FP SOURCE="FP-2">10. Mali</FP>
                    <FP SOURCE="FP-2">11. Niger</FP>
                    <FP SOURCE="FP-2">12. Seychelles (graduated from GSP)</FP>
                    <FP SOURCE="FP-2">13. Somalia</FP>
                    <FP SOURCE="FP-2">14. South Sudan</FP>
                    <FP SOURCE="FP-2">15. Sudan</FP>
                    <FP SOURCE="FP-2">16. Uganda</FP>
                    <FP SOURCE="FP-2">17. Zimbabwe</FP>
                </EXTRACT>
                <P>The AGOA TPSC Subcommittee is requesting written public comments and will conduct a virtual public hearing for this review to develop recommendations in connection with the annual review of sub-Saharan African countries' eligibility for AGOA benefits. The Secretary of Labor may consider comments related to the child labor criteria to prepare the U.S. Department of Labor's report on child labor as required under section 504 of the 1974 Act.</P>
                <HD SOURCE="HD1">II. Hearing Participation</HD>
                <P>
                    The AGOA TPSC Subcommittee will convene a virtual public hearing to receive oral testimony related to sub-Saharan African countries' eligibility for AGOA benefits via WebEx on Monday, June 27, 2024, beginning at 10:00 a.m. EDT. If you want to observe the public hearing, you will find a link on USTR's web page for sub-Saharan Africa on the day of the hearing at 
                    <E T="03">https://ustr.gov/countries-regions/africa.</E>
                </P>
                <P>
                    To ensure participation, you must submit requests to present oral testimony at the hearing and written testimony by midnight on June 6, 2024, via 
                    <E T="03">Regulations.gov,</E>
                     using Docket Number USTR-2024-0006. Instructions for submission are in sections III and IV below. Remarks at the hearing will be limited to no more than five minutes to allow for possible questions from the AGOA TPSC Subcommittee. Because the hearing will be public, testimony should not include any business confidential information (BCI). USTR will provide a link in advance of the virtual hearing to persons who have submitted requests to testify.
                </P>
                <P>The AGOA TPSC Subcommittee requests small businesses (generally defined by the Small Business Administration as firms with fewer than 500 employees) or organizations representing small business members that submit comments to self-identify as such, so that AGOA TPSC Subcommittee may be aware of issues of particular interest to small businesses.</P>
                <HD SOURCE="HD1">III. Procedures for Written Submissions</HD>
                <P>
                    To be assured of consideration, submit your pre hearing written comments, requests to testify, and written testimony by the June 6, 2024, 11:59 p.m. EDT deadline, and submit post hearing written comments by the July 11, 2024, 5:00 p.m. EDT deadline. All submission must be in English. The AGOA TPSC Subcommittee strongly encourages submissions via 
                    <E T="03">Regulations.gov,</E>
                     using Docket Number USTR-2024-0006.
                </P>
                <P>
                    To make a submission via 
                    <E T="03">Regulations.gov,</E>
                     enter Docket Number USTR-2024-0006 in the “search for” field on the home page and click “search.” The site will provide a search results page listing all documents associated with this docket. Find a reference to this notice by selecting “notice” under “document type” in the “refine documents results” section on the left side of the screen and click on the link entitled “comment.”
                </P>
                <P>
                    <E T="03">Regulations.gov</E>
                     allows users to make submissions by filling in a “type comment” field or by attaching a document using the “upload file” field. The AGOA TPSC Subcommittee prefers that you provide submissions in an attached document and note “see attached” in the “comment” field on the online submission form. The AGOA TPSC Subcommittee prefers submissions in Microsoft Word (.doc) or Adobe Acrobat (.pdf). If you use an application other than those two, please indicate the name of the application in the “type comment” field.
                </P>
                <P>
                    At the beginning of your submission or on the first page (if an attachment), include the following text: (1) 2025 AGOA Eligibility Review; (2) the relevant country or countries; and (3) whether the submission is a comment, 
                    <PRTPAGE P="42054"/>
                    request to testify, or written testimony. Submissions should not exceed 30 single-spaced, standard letter-size pages in 12-point type, including attachments. Please do not attach separate cover letters to electronic submissions; rather, include any information that might appear in a cover letter in the submission itself. Similarly, to the extent possible, please include any exhibits, annexes, or other attachments in the same file as the submission itself, not as separate files. You will receive a tracking number upon completion of the submission procedure at 
                    <E T="03">Regulations.gov.</E>
                     The tracking number is confirmation that 
                    <E T="03">Regulations.gov</E>
                     received your submission. Keep the confirmation for your records. USTR is not able to provide technical assistance for 
                    <E T="03">Regulations.gov.</E>
                </P>
                <P>
                    For further information on using 
                    <E T="03">Regulations.gov,</E>
                     please consult the resources provided on the website by clicking on “How to Use 
                    <E T="03">Regulations.gov</E>
                    ” on the bottom of the home page. The AGOA TPSC Subcommittee may not consider submissions that you do not make in accordance with these instructions.
                </P>
                <P>
                    If you are unable to provide submissions as requested, please contact Jeremy Streatfeild, Director of African Affairs, Office of African Affairs, in advance of the deadline at 
                    <E T="03">jeremy.e.streatfeild@ustr.eop.gov</E>
                     or (202) 395-8642, to arrange for an alternative method of transmission. USTR will not accept hand-delivered submissions. General information concerning USTR is available at 
                    <E T="03">www.ustr.gov.</E>
                </P>
                <HD SOURCE="HD1">IV. Business Confidential Information (BCI) Submissions</HD>
                <P>If you ask the AGOA TPSC Subcommittee to treat information you submit as BCI, you must certify that the information is business confidential and you would not customarily release it to the public. For any comments submitted electronically that contain BCI, the file name of the business confidential version should begin with the characters “BCI.” You must clearly mark any page containing BCI with “BUSINESS CONFIDENTIAL” at the top of that page. Filers of submissions containing BCI also must submit a public version of their submission that will be placed in the docket for public inspection. The file name of the public version should begin with the character “P.”</P>
                <HD SOURCE="HD1">V. Public Viewing of Review Submissions</HD>
                <P>
                    USTR will post written submissions in the docket for public inspection, except properly designated BCI. You can view submissions at 
                    <E T="03">Regulations.gov</E>
                     by entering Docket Number USTR-2024-XXXX in the search field on the home page.
                </P>
                <SIG>
                    <NAME>Laura Buffo,</NAME>
                    <TITLE>Chair of the Trade Policy Staff Committee, Office of the United States Trade Representative.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10482 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 3390-F4-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF TRANSPORTATION</AGENCY>
                <SUBAGY>Federal Motor Carrier Safety Administration</SUBAGY>
                <DEPDOC>[Docket No. FMCSA-2018-0346]</DEPDOC>
                <SUBJECT>Safe Driver Apprenticeship Pilot Program To Allow Persons Ages 18, 19, and 20 To Operate Commercial Motor Vehicles in Interstate Commerce; Revision to Program Requirements</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Motor Carrier Safety Administration (FMCSA), Department of Transportation (DOT).</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of revision to pilot program.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>
                        The Infrastructure Investment and Jobs Act (IIJA), which was signed into law on November 15, 2021, required FMCSA to establish a pilot program that would allow employers to establish an apprenticeship program for certain 18-, 19-, and 20-year-old drivers to operate commercial vehicles in interstate commerce. FMCSA announced the establishment of the Safe Driver Apprenticeship Pilot (SDAP) Program in the 
                        <E T="04">Federal Register</E>
                         on January 14, 2022, including the requirements for motor carriers wishing to participate. This notice revises those requirements, as directed by Congress in the Consolidated Appropriations Act, 2024.
                    </P>
                </SUM>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Ms. Nikki McDavid, Commercial Driver's License Division, Federal Motor Carrier Safety Administration, 1200 New Jersey Avenue SE, Washington, DC 20590-0001, 
                        <E T="03">nikki.mcdavid@dot.gov,</E>
                         (202) 366-0831. If you have questions about viewing or submitting material to the docket, call DOT Dockets Operations, (202) 366-9826.
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">I. Background</HD>
                <P>
                    FMCSA announced the SDAP Program in the 
                    <E T="04">Federal Register</E>
                     on January 14, 2022 (87 FR 2477). In that notice, FMCSA included motor carrier requirements for participation, including installation and use of inward facing cameras. FMCSA also included a requirement that motor carriers receive approval as a Registered Apprenticeship Program from the Department of Labor (DOL), in accordance with 29 CFR part 29.
                </P>
                <P>On March 9, 2024, the President signed the Consolidated Appropriations Act, 2024 (Pub. L. 118-42). Section 422 of that Act states that FMCSA may not require motor carriers, wishing to participate in the SDAP Program, use inward facing cameras, or require them to become Registered Apprenticeships under DOL regulations.</P>
                <HD SOURCE="HD1">II. Revision</HD>
                <P>In accordance with the Consolidated Appropriations Act, 2024, FMCSA will no longer require that motor carriers wishing to participate in the SDAP Program install or use inward facing cameras. Additionally, motor carriers will not be required to obtain a Registered Apprenticeship number from the Department of Labor before they will be allowed to participate in the SDAP Program.</P>
                <HD SOURCE="HD1">III. Pilot Program Requirements and Procedures</HD>
                <HD SOURCE="HD2">Information Collection Approval</HD>
                <P>In accordance with the Paperwork Reduction Act (PRA) of 1995, FMCSA is requesting that the Office of Management and Budget (OMB) grant emergency clearance for a revision to the approved information collection titled, “Safe Driver Apprenticeship Pilot Program,” ICR Control Number 2126-0075. The emergency request updates the collection to reflect the Consolidated Appropriations Act, 2024, but notes that the expected data collection burdens on participants in the pilot program are not expected to change from those included in the collection that was approved in 2022. FMCSA requested that OMB approve the revision by April 15, 2024, to allow the changes to be in place in time for the next monthly reports for currently approved motor carriers. FMCSA is not requesting that OMB extend the approval of the collection beyond the currently approved expiration date of October 31, 2025.</P>
                <HD SOURCE="HD2">Announcement of Revision to the Safe Driver Apprenticeship Pilot Program</HD>
                <P>
                    In accordance with the Consolidated Appropriations Act, 2024, FMCSA will no longer require motor carriers wishing to participate in the SDAP Program install or use inward facing cameras. Additionally, motor carriers will not be required to obtain a Registered Apprenticeship number from the Department of Labor before they will be 
                    <PRTPAGE P="42055"/>
                    allowed to participate in the SDAP Program.
                </P>
                <P>Motor carriers who are already participating in the SDAP Program will no longer be required to use inward facing cameras, or to maintain their approved Registered Apprenticeship program.</P>
                <P>Motor carriers may, voluntarily, decide to install or use inward facing cameras, or become an approved Registered Apprenticeship. They may choose to include safety alerts from inward facing cameras as part of their monthly data submissions. However, they will not be required to do so, even if they choose to use inward facing cameras.</P>
                <HD SOURCE="HD2">Motor Carrier Applications Available</HD>
                <P>
                    FMCSA is accepting applications from motor carriers for the pilot program. Links for the application, which has been revised to conform with the Consolidated Appropriations Act, 2024, are available on the Agency's website at 
                    <E T="03">www.fmcsa.dot.gov.</E>
                     FMCSA will, proactively, reach out to motor carriers who previously submitted applications but were missing Registered Apprenticeship numbers to determine whether the motor carriers are still interested in participating in the SDAP Program.
                </P>
                <P>All other motor carrier requirements remain unchanged from the notice published on January 14, 2022 (87 FR 2477).</P>
                <SIG>
                    <NAME>Sue Lawless,</NAME>
                    <TITLE>Acting Deputy Administrator.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10538 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4910-EX-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF TRANSPORTATION</AGENCY>
                <SUBAGY>Federal Motor Carrier Safety Administration</SUBAGY>
                <DEPDOC>[Docket No. FMCSA-2015-0480]</DEPDOC>
                <SUBJECT>Commercial Driver's License Standards: Application for Exemption Renewal; CRST The Transportation Solution (Formerly Known as CRST Expedited, Inc.)</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Federal Motor Carrier Safety Administration (FMCSA), Department of Transportation (DOT).</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice of final exemption renewal; renewal of exemption.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>FMCSA announces its decision to renew the exemption currently held by CRST The Transportation Solution (CRST) (formerly known as CRST Expedited, Inc.) from the requirement that a commercial driver's license (CDL) holder with the proper CDL class and endorsements be seated in the front seat of the commercial motor vehicle (CMV) at all times while the commercial learner's permit (CLP) holder is engaged in behind-the-wheel training on public roads or highways. FMCSA announced its decision to provisionally renew CRST's exemption on August 7, 2023, pending a review of any comments received in response to that notice. Two comments opposing the exemption were submitted to the docket and are discussed below. The Agency believes that CRST and its drivers covered by the exemption will maintain a level of safety that is equivalent to, or greater than, the level of safety that would be achieved by complying with the regulatory requirement.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>This renewed exemption was effective September 24, 2023, and expires on September 24, 2028.</P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Mrs. Pearlie Robinson, Driver and Carrier Operations Division; Office of Carrier, Driver and Vehicle Safety Standards, FMCSA; 202-366-4225; 
                        <E T="03">pearlie.robinson@dot.gov.</E>
                         If you have questions on viewing or submitting material to the docket, contact Dockets Operations, (202) 366-9826.
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">I. Public Participation</HD>
                <HD SOURCE="HD2">Viewing Comments and Documents</HD>
                <P>
                    To view comments, go to 
                    <E T="03">www.regulations.gov,</E>
                     insert the docket number “FMCSA-2015-0480” in the keyword box, and click “Search.” Next, sort the results by “Posted (Newer-Older),” choose the first notice listed, and click “Browse Comments.”
                </P>
                <P>
                    To view documents mentioned in this notice as being available in the docket, go to 
                    <E T="03">www.regulations.gov,</E>
                     insert the docket number “FMCSA-2015-0480” in the keyword box, click “Search,” and choose the document to review.
                </P>
                <P>If you do not have access to the internet, you may view the docket online by visiting Dockets Operations on the ground floor of the DOT West Building, 1200 New Jersey Avenue SE, Washington, DC 20590, between 9 a.m. and 5 p.m., ET, Monday through Friday, except Federal holidays. To be sure someone is there to help you, please call (202) 366-9317 or (202) 366-9826 before visiting Dockets Operations.</P>
                <HD SOURCE="HD1">II. Legal Basis</HD>
                <P>FMCSA has authority under 49 U.S.C. 31136(e) and 31315(b)(2), and 49 CFR 381.300(b), to renew an exemption from the FMCSA regulations specified in 49 CFR 381.300(c) for up to 5 years, if it finds that “such exemption would likely achieve a level of safety that is equivalent to, or greater than, the level that would be achieved absent such exemption.” (49 U.S.C. 31315(b)(1)). On August 7, 2023, FMCSA evaluated CRST's application and provisionally renewed the exemption from 49 CFR 383.25(a)(1) for a five-year period, from September 24, 2023, through September 24, 2028 (88 FR 52241).</P>
                <HD SOURCE="HD1">III. Background</HD>
                <HD SOURCE="HD2">Current Regulatory Requirements</HD>
                <P>FMCSA's CDL regulations in 49 CFR 383.25 establish minimum requirements for a CLP to be considered a valid CDL during behind-the-wheel training of a CLP holder on public roads or highways. Section 383.25(a)(1) requires a CDL holder with the proper CDL class and endorsements necessary to operate the CMV to accompany a CLP holder and be physically present in the front seat of the CMV next to the CLP holder at all times or, in a commercial passenger vehicle, directly behind or in the front row behind the driver and must have the CLP holder under observation and direct supervision.</P>
                <HD SOURCE="HD1">IV. Application for Renewal of Exemption</HD>
                <P>CRST requested a second renewal of an exemption from the CDL requirements in 49 CFR 383.25(a)(1). Under the exemption, a CLP holder who has passed the skills test but not yet received the CDL document may drive a CMV accompanied by a CDL holder who is not necessarily in the passenger seat, provided the CLP driver possesses documentation of passing the skills test from the State that administered the test.</P>
                <HD SOURCE="HD1">V. Public Comments</HD>
                <P>On August 7, 2023, FMCSA published its decision to provisionally grant a five-year renewal of CRST's original exemption, through September 24, 2028, and asked for public comment (88 FR 52241). Two comments were submitted to the docket, both opposed to the exemption renewal.</P>
                <P>An anonymous individual said, “Do not allow rookie drivers on the road. This is killing and injuring many people. Inside Edition did a report on the increase of trucking deaths from drivers without much experience. CRST wants to make money without any accountability on the experience level of their drivers. When will our government put people over profits?”</P>
                <P>
                    A joint comment was filed by the Truck Safety Coalition, Citizens for Reliable and Safe Highways, and 
                    <PRTPAGE P="42056"/>
                    Parents Against Tired Truckers. In the joint comment, the organizations contended that CRST has never demonstrated that the exemption met the equivalent level of safety requirements under 49 U.S.C. 31136(e) and 31315(b)(2) and therefore the exemption should never have been granted. The commenters also asserted that the exemption undermines the safety benefits provided by the direct supervision of a CDL holder and, moreover, that CRST's publicly available safety and inspection data “does not inspire confidence.”
                </P>
                <HD SOURCE="HD1">VI. Response to Public Comments and Agency Decision</HD>
                <P>The main premise of commenters opposing the exemption is that CLP holders lack experience and are safer drivers when directly observed by a CDL holder who is on duty and in the front seat of the vehicle. FMCSA notes, however, that CLP holders who have passed the CDL skills test have demonstrated their abilities to safely operate the CMV. The exemption therefore applies only to CRST drivers who have completed required entry-level driver training requirements, set forth in 49 CFR part 380, subpart F, and passed the CDL skills test. If these CLP holders had passed the skills test in their State of domicile, they could immediately obtain their CDL or temporary CDL and begin driving CMVs without any on-board supervision. Drivers who have passed the CDL skills test outside their State of domicile must obtain the physical CDL credential from their State of domicile. The exemption permits these individuals who are employed by CRST to work productively as team CMV drivers during the period between passing the skills test and receiving their CDL, without requiring the accompanying CDL holders to be on duty and in the front seat.</P>
                <P>In response to the comment regarding CRST's safety record, the Agency believes that CRST's overall safety performance, as reflected in its “satisfactory” safety rating, will enable it to maintain a level of safety that is equivalent to, or greater than, the level of safety achieved without the exemption (49 CFR 381.305(a)). The specific basis for the Agency's conclusions on the safety equivalence of operations conducted under this exemption are set forth in FMCSA's August 7, 2023, provisional renewal Notice, referenced above.</P>
                <SIG>
                    <NAME>Sue Lawless,</NAME>
                    <TITLE>Acting Deputy Administrator.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10540 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4910-EX-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF THE TREASURY</AGENCY>
                <SUBAGY>Internal Revenue Service</SUBAGY>
                <SUBJECT>Proposed Collection; Requesting Comments on Form 3115</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Internal Revenue Service (IRS), Treasury.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice and request for comments.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Internal Revenue Service, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995. The IRS is soliciting comments concerning Form 3115, Application for Change in Accounting Method.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Written comments should be received on or before July 15, 2024 to be assured of consideration.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Direct all written comments to Andres Garcia, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW, Washington, DC 20224, or by email to 
                        <E T="03">pra.comments@irs.gov.</E>
                         Include OMB Control Number 1545-2070 in the subject line of the message.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Requests for additional information or copies of this collection should be directed to Sara Covington, (202) 317-5744, at Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW, Washington, DC 20224, or through the internet at 
                        <E T="03">sara.l.covington@irs.gov.</E>
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P>The IRS is currently seeking comments concerning the following information collection tools, reporting, and record-keeping requirements:</P>
                <P>
                    <E T="03">Title:</E>
                     Form 3115, Application for Change in Accounting Method.
                </P>
                <P>
                    <E T="03">OMB Number:</E>
                     1545-2070.
                </P>
                <P>
                    <E T="03">Form Number:</E>
                     Form 3115.
                </P>
                <P>
                    <E T="03">Abstract:</E>
                     Internal Revenue Code (IRC) section 446(e) provides that a taxpaying entity that changes its method of accounting for computing taxable income must first secure the consent of the Secretary. The taxpayer uses Form 3115 to obtain this consent.
                </P>
                <P>
                    <E T="03">Current Actions:</E>
                     There are no changes being made to the form at this time.
                </P>
                <P>
                    <E T="03">Type of Review:</E>
                     Extension of a currently approved collection.
                </P>
                <P>
                    <E T="03">Affected Public:</E>
                     Estates, trusts, and not-for-profit institutions.
                </P>
                <P>
                    <E T="03">Estimated Number of Responses:</E>
                     183.
                </P>
                <P>
                    <E T="03">Estimated Time per Respondent:</E>
                     99.99 hours.
                </P>
                <P>
                    <E T="03">Estimated Total Annual Burden Hours:</E>
                     18,298.
                </P>
                <P>The following paragraph applies to all of the collections of information covered by this notice:</P>
                <P>An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.</P>
                <P>
                    <E T="03">Request for Comments:</E>
                     Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval. All comments will become a matter of public record. Comments are invited on: (a) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology; and (e) estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services to provide information.
                </P>
                <SIG>
                    <DATED>Approved: May 8, 2024.</DATED>
                    <NAME>Sara L. Covington,</NAME>
                    <TITLE>IRS Tax Analyst.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10486 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 4830-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="N">DEPARTMENT OF VETERANS AFFAIRS</AGENCY>
                <DEPDOC>[OMB Control No. 2900-0798]</DEPDOC>
                <SUBJECT>Agency Information Collection Activity Under OMB Review: Veteran/Beneficiary Claim for Reimbursement of Travel Expenses</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Veterans Health Administration, Department of Veterans Affairs.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Notice.</P>
                </ACT>
                <SUM>
                    <PRTPAGE P="42057"/>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>In compliance with the Paperwork Reduction Act (PRA) of 1995, this notice announces that the Veterans Health Administration, Department of Veterans Affairs (VA), will submit the collection of information abstracted below to the Office of Management and Budget (OMB) for review and comment. The PRA submission describes the nature of the information collection and its expected cost and burden and it includes the actual data collection instrument.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>
                        Written comments and recommendations for the proposed information collection should be sent within 30 days of publication of this notice to 
                        <E T="03">www.reginfo.gov/public/do/PRAMain.</E>
                         Find this particular information collection by selecting “Currently under 30-day Review—Open for Public Comments” or by using the search function. Refer to “OMB Control No. 2900-0798.”
                    </P>
                </DATES>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>
                        Maribel Aponte, (202) 266-4688, 
                        <E T="03">vacopaperworkreduact@va.gov.</E>
                         Please refer to “OMB Control No. 2900-0798” in any correspondence.
                    </P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <P/>
                <P>
                    <E T="03">Authority:</E>
                     44 U.S.C. 3501-3521.
                </P>
                <P>
                    <E T="03">Title:</E>
                     Veteran/Beneficiary Claim for Reimbursement of Travel Expenses (VA Form 10-3542 and BTSSS).
                </P>
                <P>
                    <E T="03">OMB Control Number:</E>
                     2900-0798.
                </P>
                <P>
                    <E T="03">Type of Review:</E>
                     Reinstatement, with change, of a previously approved collection.
                </P>
                <P>
                    <E T="03">Abstract:</E>
                     Pursuant to 38 U.S.C. 111 and 38 CFR part 70, subpart A, the Veterans Health Administration (VHA) Beneficiary Travel (BT) Program provides payments for authorized travel expenses to help Veterans and other beneficiaries obtain care or services from VHA or VA-authorized providers in the community. VHA must administer payments according to statutory mandates, including the Payment Integrity Information Act of 2019 (PIIA) (Pub. L. 116-117). In compliance with the PIIA and other program requirements, VHA must gather certain information to determine whether BT eligibility and other criteria for approval have been met, and the amount of payment or reimbursement that is authorized under the BT program.
                </P>
                <P>Claimants may include Veterans and other BT beneficiaries, as well as entities or individuals who provided or paid for travel. Claimants may apply for BT orally or in writing through VA Form 10-3542 or the Beneficiary Travel Self-Service System (BTSSS). This standard collection of information is necessary to enable VHA to provide this benefit and appropriately ensure that funds are being paid to the correct claimant.</P>
                <P>
                    An agency may not conduct or sponsor, and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number. The 
                    <E T="04">Federal Register</E>
                     Notice with a 60-day comment period soliciting comments on this collection of information was published at 89 FR 15928, March 5, 2024.
                </P>
                <P>
                    <E T="03">Total Annual Burden:</E>
                     1,216,667 hours.
                </P>
                <P>
                    <E T="03">Total Annual Responses:</E>
                     7,300,000.
                </P>
                <P>
                    <E T="03">Affected Public:</E>
                     Individuals or Households.
                </P>
                <P>
                    <E T="03">Estimated Annual Burden:</E>
                     1,216,667 hours.
                </P>
                <P>
                    <E T="03">Estimated Average Burden Per Response:</E>
                     10 minutes.
                </P>
                <P>
                    <E T="03">Frequency of Response:</E>
                     Average of 5 times per year.
                </P>
                <P>
                    <E T="03">Estimated Number of Respondents:</E>
                     1,460,000.
                </P>
                <SIG>
                    <P>By direction of the Secretary.</P>
                    <NAME>Maribel Aponte,</NAME>
                    <TITLE>VA PRA Clearance Officer, Office of Enterprise and Integration, Data Governance Analytics, Department of Veterans Affairs.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10461 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 8320-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF VETERANS AFFAIRS</AGENCY>
                <SUBJECT>Notice of Request for Information on the Department of Veterans Affairs Nuclear Medicine Technologist Standard of Practice</SUBJECT>
                <AGY>
                    <HD SOURCE="HED">AGENCY:</HD>
                    <P>Department of Veterans Affairs.</P>
                </AGY>
                <ACT>
                    <HD SOURCE="HED">ACTION:</HD>
                    <P>Request for information.</P>
                </ACT>
                <SUM>
                    <HD SOURCE="HED">SUMMARY:</HD>
                    <P>The Department of Veterans Affairs (VA) is requesting information to assist in developing a national standard of practice for VA Nuclear Medicine Technologists. VA seeks comments on various topics to help inform VA's development of this national standard of practice.</P>
                </SUM>
                <DATES>
                    <HD SOURCE="HED">DATES:</HD>
                    <P>Comments must be received on or before July 15, 2024.</P>
                </DATES>
                <ADD>
                    <HD SOURCE="HED">ADDRESSES:</HD>
                    <P>
                        Comments must be submitted through 
                        <E T="03">https://www.regulations.gov/.</E>
                         Except as provided below, comments received before the close of the comment period will be available at 
                        <E T="03">https://www.regulations.gov/</E>
                         for public viewing, inspection, or copying, including any personally identifiable or confidential business information that is included in a comment. We post the comments received before the close of the comment period on the following website as soon as possible after they have been received: 
                        <E T="03">https://www.regulations.gov/.</E>
                         VA will not post on 
                        <E T="03">https://www.regulations.gov/</E>
                         public comments that make threats to individuals or institutions or suggest that the commenter will take actions to harm the individual. VA encourages individuals not to submit duplicative comments. We will post acceptable comments from multiple unique commenters even if the content is identical or nearly identical to other comments. Any public comment received after the comment period's closing date will not be considered.
                    </P>
                </ADD>
                <FURINF>
                    <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                    <P>Ethan Kalett, Office of Regulations, Appeals and Policy (10BRAP), Veterans Health Administration, Department of Veterans Affairs, 810 Vermont Avenue NW, Washington, DC 20420, 202-461-0500. This is not a toll-free number.</P>
                </FURINF>
            </PREAMB>
            <SUPLINF>
                <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                <HD SOURCE="HD1">Authority</HD>
                <P>Chapters 73 and 74 of 38 U.S.C. and 38 U.S.C. 303 authorize the Secretary to regulate VA health care professions to make certain that VA's health care system provides safe and effective health care by qualified health care professionals to ensure the well-being of those Veterans who have borne the battle.</P>
                <P>On November 12, 2020, VA published an interim final rule confirming that VA health care professionals may practice their health care profession consistent with the scope and requirements of their VA employment, notwithstanding any State license, registration, certification, or other State requirements that unduly interfere with their practice. 38 CFR 17.419; 85 FR 71838. Specifically, this rulemaking confirmed VA's current practice of allowing VA health care professionals to deliver health care services in a State other than the health care professional's State of licensure, registration, certification, or other State requirement, thereby enhancing beneficiaries' access to critical VA health care services. The rulemaking also confirmed VA's authority to establish national standards of practice for its health care professionals, which would standardize a health care professional's practice in all VA medical facilities, regardless of conflicting State laws, rules, regulations, or other State requirements.</P>
                <P>
                    The rulemaking explained that a national standard of practice describes the tasks and duties that a VA health care professional practicing in the health care profession may perform and may be permitted to undertake. Having 
                    <PRTPAGE P="42058"/>
                    a national standard of practice means that individuals from the same VA health care profession may provide the same type of tasks and duties regardless of the State where they are located or the State license, registration, certification, or other State requirement they hold. We emphasized in the rulemaking and reiterate here that VA will determine, on an individual basis, that a health care professional has the proper education, training, and skills to perform the tasks and duties detailed in the national standard of practice, and that they will only be able to perform such tasks and duties after they have been incorporated into the individual's privileges, scope of practice, or functional statement. The rulemaking explicitly did not create any such national standards and directed that all national standards of practice would be subsequently created via policy.
                </P>
                <HD SOURCE="HD1">Preemption of State Requirements</HD>
                <P>The national standard of practice will preempt any State laws, rules, regulations, or requirements that both are and are not listed in the national standard as conflicting, but that do in fact conflict with the tasks and duties as authorized in VA's national standard of practice. In the event that a State changes their requirements and places new limitations on the tasks and duties it allows in a manner that would be inconsistent with what is authorized under the national standard of practice, the national standard of practice will preempt such limitations and authorize the VA health care professional to continue to practice consistently with the tasks and duties outlined in the national standard of practice.</P>
                <P>In cases where a VA health care professional's license, registration, certification, or other State requirement allows a practice that is not included in a national standard of practice, the individual may continue that practice so long as it is permissible by Federal law and VA policy, is not explicitly prohibited by the national standard of practice and is approved by the VA medical facility.</P>
                <HD SOURCE="HD1">Need for National Standards of Practice</HD>
                <P>It is critical that VA, the Nation's largest integrated health care system, develops national standards of practice to ensure, first, that beneficiaries receive the same high-quality care regardless of where they enter the system and, second, that VA health care professionals can efficiently meet the needs of beneficiaries when practicing within the scope of their VA employment. National standards are designed to increase beneficiaries' access to safe and effective health care, thereby improving health outcomes. The importance of this initiative has been underscored by the Coronavirus Disease 2019 (COVID-19) pandemic. The increased need for mobility in VA's workforce, including through VA's Disaster Emergency Medical Personnel System, highlighted the importance of creating uniform national standards of practice to better support VA health care professionals who practice across State lines. Creating national standards of practice also promotes interoperability of medical data between VA and the Department of Defense (DoD), providing a complete picture of a Veteran's health information and improving VA's delivery of health care to the Nation's Veterans. DoD has historically standardized practice for certain health care professionals, and VA has closely partnered with DoD to learn from their experience.</P>
                <HD SOURCE="HD1">Process To Develop National Standards of Practice</HD>
                <P>
                    As authorized by 38 CFR 17.419, VA is developing national standards of practice via policy. There is one overarching directive to describe Veterans Health Administration (VHA) policy on national standards of practice. The directive is accessible on the VHA Publications website at 
                    <E T="03">https://vaww.va.gov/vhapublications/</E>
                     (internal) and 
                    <E T="03">https://www.va.gov/vhapublications/</E>
                     (external). As each individual national standard of practice is finalized, it is published as an appendix to the directive and accessible at the same websites.
                </P>
                <P>To develop these national standards, VA is using a robust, interactive process that adheres to the guidelines outlined in Executive Order (E.O.) 13132 to preempt conflicting State laws, rules, regulations, or other requirements. The process includes consultation with internal and external stakeholders, including State licensing boards, VA employees, professional associations, Veterans Service Organizations, labor partners, and others. For each VA occupation, a workgroup comprised of VA health care professionals in the identified occupation conducts research to identify internal best practices that may not be authorized under every State license, certification, or registration but would enhance the practice and efficiency of the profession throughout VA. If a best practice is identified that is not currently authorized by every State, the workgroup determines what education, training, and skills are required to perform such tasks and duties. The workgroup then drafts a proposed VA national standard of practice using the data gathered during the research and incorporates internal stakeholder feedback into the standard. The workgroup may consult with internal or external stakeholders at any point throughout the process.</P>
                <P>The proposed national standard of practice is then internally reviewed, to include by an interdisciplinary VA workgroup consisting of representatives from Quality Management, VA medical facility Chiefs of Staff, Academic Affiliates, Veterans Integrated Services Network (VISN) Chief Nursing Officers, Ethics, Workforce Management and Consulting, Surgery, Credentialing and Privileging, VISN Chief Medical Officers, and Electronic Health Record Modernization.</P>
                <P>Externally, VA hosts listening sessions for members of the public, professional associations, and VA employees to provide comments on the variance between State practice acts for specific occupations and what should be included in the national standard of practice for that occupation. The listening session for Nuclear Medicine Technologists on September 7, 2023, included five presenters, representing VA employees and the Nuclear Medicine Technology Certification Board. The presenters spoke about the qualifications of and scope of practice for Nuclear Medicine Technologists. Presenters were supportive of the national standard of practice. VA appreciates the thoughtful presentations and is considering the information presented at the listening session when drafting the proposed VA national standard of practice.</P>
                <P>
                    VA has developed a robust process to engage with partners, members of the public, States, and employees on the proposed national standard of practice. VA provides the proposed national standard of practice to our DoD partners as an opportunity to flag inconsistencies with DoD standards. VA also engages with labor partners informally as part of a pre-decisional collaboration. Consistent with E.O. 13132, VA sends a letter to each State board and certifying organization or registration organization, as appropriate, which includes the proposed national standard and offers the recipient an opportunity to discuss the national standard with VA. After the State boards, certifying organizations, or registration organizations have received notification, the proposed national standard of practice is posted in the 
                    <E T="04">Federal Register</E>
                     for 60 days to obtain feedback from the public, professional associations, and any other interested parties. At the same time, the proposed national standard is posted to an 
                    <PRTPAGE P="42059"/>
                    internal VA site to obtain feedback from VA employees. Responses received through all vehicles—from State boards, professional associations, unions, VA employees, and any other individual or organization who provides comments via the 
                    <E T="04">Federal Register</E>
                    —will be reviewed. VA will make appropriate revisions in light of the comments, including those that present evidence-based practice and alternatives that help VA meet our mission and goals. VA will publish a collective response to all comments at 
                    <E T="03">https://www.va.gov/standardsofpractice/.</E>
                </P>
                <P>After the national standard of practice is finalized, approved, and published in VHA policy, VA will implement the tasks and duties authorized by that national standard of practice. Any tasks or duties included in the national standard will be properly incorporated into an individual health care professional's privileges, scope of practice, or functional statement once it has been determined by their VA medical facility that the individual has the proper education, training, and skills to perform the task or duty. Implementation of the national standard of practice may be phased in across all VA medical facilities, with limited exemptions for health care professionals, as needed.</P>
                <HD SOURCE="HD1">Format for the Proposed National Standard for Nuclear Medicine Technologists</HD>
                <P>The format for the proposed national standards of practice when there are national certification bodies and State licenses is described as follows. The first paragraph provides general information about the profession and what the health care professionals can do. For this national standard, Nuclear Medicine Technologists administer radionuclides, radiopharmaceuticals, and adjunct medications under the direction of a Nuclear Medicine Physician or Radiologist. We reiterate that the proposed standard of practice does not contain an exhaustive list of every task and duty that each VA health care professional can perform. Rather, it is designed to highlight generally what tasks and duties the health care professionals perform and how they will be able to practice within VA notwithstanding their State license, certification, registration, or other State requirements.</P>
                <P>The second paragraph references the education and certification needed to practice this profession at VA. Qualification standards for employment of health care professionals by VA are outlined in VA Handbook 5005, Staffing, dated April 8, 2024. VA follows the requirements outlined in the VA qualification standards even if the requirements conflict with or differ from a State requirement. National standards of practice do not affect those requirements. This includes, but is not limited to, when a State requires a license to practice a specific occupation, but VA does not require a State license as part of the qualification standards. For Nuclear Medicine Technologists, VA qualification standards require an active, current, full, and unrestricted certification from the Nuclear Medicine Technology Certification Board (NMTCB) or the American Registry of Radiologic Technology (ARRT).</P>
                <P>The second paragraph also notes whether the national standard of practice explicitly excludes individuals who practice under “grandfathering” provisions. Qualification standards may include provisions to permit employees who met all requirements prior to revisions to the qualification standards to maintain employment at VA even if they no longer meet the new qualification standards. This practice is referred to as grandfathering. Nuclear Medicine Technologists have grandfathering provisions included within their qualification standards, and VA proposes to have those individuals be authorized to follow the Nuclear Medicine Technologist national standard of practice. Therefore, there would be no notation regarding grandfathered employees in the national standard of practice as they would be required to adhere to the national standard as would any other VA Nuclear Medicine Technologist who meets the current qualification standards.</P>
                <P>
                    The third paragraph establishes what the national standard of practice will be for the occupation in VA. For this national standard, VA Nuclear Medicine Technologists follow the standard set by Society of Nuclear Medicine and Molecular Imaging (SNMMI), which can be found at: 
                    <E T="03">https://www.snmmi.org/Technologists.</E>
                     For Nuclear Medicine Technologists, VA confirmed that all individuals, whether certified by NMTCB or ARRT, followed the Nuclear Medicine Technologist Scope of Practice and Performance Standards from SNMMI.
                </P>
                <P>The fourth paragraph identifies if there are additional registrations, regulations, certifications, licenses, or Federal exemptions for the profession. It explains if VA is preempting any conflicting State laws, rules, regulations, or requirements. For this national standard of practice, VA reviewed if there are any required alternative registrations, certifications, licenses, or other State requirements for Nuclear Medicine Technologists. VA found that 34 States require a State license for Nuclear Medicine Technologists.</P>
                <P>The fourth paragraph also includes information on which States offer an exemption for Federal employees and whether VA is preempting any conflicting State laws, rules, regulations, or requirements. Of those 34 States that require a license, 24 States exempt Federal employees from their State license requirements. Furthermore, the tasks and duties set forth in the State license requirements for all 34 States are consistent with what is permitted under the national certification. Therefore, there is no variance in how Nuclear Medicine Technologists practice in any State. VA thus proposes to adopt a standard of practice consistent with the national certification. VA Nuclear Medicine Technologists will continue to follow this standard.</P>
                <P>This national standard or practice does not address training because it will not authorize VA Nuclear Medicine Technologists to perform any tasks or duties not already authorized under their national certification and State license.</P>
                <P>Following public and VA employee comments and revisions, each national standard of practice that is published in policy will also include the date for recertification of the standard of practice and a point of contact for questions or concerns.</P>
                <HD SOURCE="HD1">Proposed National Standard of Practice for Nuclear Medicine Technologists</HD>
                <P>
                    1. Nuclear Medicine Technologists perform technical work in support of the Diagnostic Imaging Service's Nuclear Medicine section under the direction of a Nuclear Medicine Physician or Radiologist. Nuclear Medicine Technologists administer radionuclides, radiopharmaceuticals, and adjunct medications. They also operate radiation detectors, scanning apparatus, and related equipment for patients having General Nuclear Medicine, Nuclear Cardiology, Positron Emission Tomography and Computerized Tomography (PET/CT), and Positron Emission Tomography and Magnetic Resonance Imaging (PET/MRI) exams. Under the supervision of an authorized user, Nuclear Medicine Technologists are responsible for the safe use of ionizing and non-ionizing radiation and molecular imaging for diagnostic, therapeutic, and research purposes. Nuclear Medicine Technologists review patients' medical histories to understand their illnesses, medical issues, and pending diagnostic or treatment procedures; instruct 
                    <PRTPAGE P="42060"/>
                    patients before, during, and following procedures; evaluate the satisfactory preparation of patients before beginning procedures; complete documentation within electronic health records as necessary; and recognize and respond appropriately to emergency situations.
                </P>
                <P>2. Nuclear Medicine Technologists in the Department of Veterans Affairs (VA) possess the education and certification required by VA qualification standards. See VA Handbook 5005, Staffing, part II, appendix G19, dated December 10, 2019.</P>
                <P>
                    3. VA Nuclear Medicine Technologists practice in accordance with the Nuclear Medicine Technologist Scope of Practice and Performance Standards from the Society of Nuclear Medicine and Molecular Imaging (SNMMI), available at 
                    <E T="03">https://www.snmmi.org/Technologists.</E>
                     Nuclear Medicine Technology Certification Board and the American Registry of Radiologic Technology, the two national certifying bodies of Nuclear Medicine Technologists, follow the SNMMI standards. VA reviewed license and certification requirements for this occupation in September 2023 and confirmed that all Nuclear Medicine Technologists in VA followed SNMMI standards.
                </P>
                <P>4. Although VA only requires a certification, 34 States require a State license in order to practice as a Nuclear Medicine Technologist in that State: Alaska, Arizona, Arkansas, California, Delaware, Florida, Hawaii, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maine, Maryland, Massachusetts, Mississippi, Nevada, New Hampshire, New Jersey, New Mexico, New York, North Dakota, Ohio, Oregon, Puerto Rico, Rhode Island, South Carolina, Texas, Utah, Vermont, Virginia, West Virginia, and Wyoming.</P>
                <P>Of those, 24 States exempt Federal employees from their State license requirements: Alaska, Arizona, California, Delaware, Florida, Illinois, Iowa, Kansas, Kentucky, Maine, Maryland, Massachusetts, Nevada, New Hampshire, New Jersey, New York, North Dakota, Ohio, Oregon, Texas, Utah, Vermont, Virginia, and West Virginia.</P>
                <P>VA reviewed license and certification requirements for this occupation in September 2023 and confirmed there was no variance in how VA Nuclear Medicine Technologists practice in any State.</P>
                <HD SOURCE="HD1">Request for Information</HD>
                <P>1. Are there any additional trainings for the aforementioned tasks and duties where VA is preempting States that we should consider?</P>
                <P>2. Are there any factors that would inhibit or delay the implementation of the aforementioned tasks and duties for VA health care professionals in any States?</P>
                <P>3. Is there any variance in tasks and duties that we have not listed?</P>
                <P>4. What should we consider when preempting conflicting State laws, rules, regulations, or requirements regarding supervision of individuals working toward obtaining their license or unlicensed personnel?</P>
                <P>5. Is there anything else you would like to share with us about this national standard of practice?</P>
                <HD SOURCE="HD1">Signing Authority</HD>
                <P>Denis McDonough, Secretary of Veterans Affairs, approved and signed this document on April 25, 2024, and authorized the undersigned to sign and submit the document to the Office of the Federal Register for publication electronically as an official document of the Department of Veterans Affairs.</P>
                <SIG>
                    <NAME>Luvenia Potts,</NAME>
                    <TITLE>Regulation Development Coordinator, Office of Regulation Policy &amp; Management, Office of General Counsel, Department of Veterans Affairs.</TITLE>
                </SIG>
            </SUPLINF>
            <FRDOC>[FR Doc. 2024-10528 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE 8320-01-P</BILCOD>
        </NOTICE>
        <NOTICE>
            <PREAMB>
                <AGENCY TYPE="S">DEPARTMENT OF VETERANS AFFAIRS</AGENCY>
                <SUBJECT>Veterans' Family, Caregiver and Survivor Advisory Committee, Notice of Meeting</SUBJECT>
                <P>The Department of Veterans Affairs (VA) gives notice under the Federal Advisory Committee Act, 5 U.S.C. ch. 10, that the Veterans' Family, Caregiver and Survivor Advisory Committee will meet virtually on June 3, 2024. The meeting session will begin and end as follows:</P>
                <GPOTABLE COLS="2" OPTS="L2,tp0,i1" CDEF="s50,r50">
                    <BOXHD>
                        <CHED H="1">Date</CHED>
                        <CHED H="1">Time</CHED>
                    </BOXHD>
                    <ROW>
                        <ENT I="01">June 3, 2024</ENT>
                        <ENT>10:00 a.m. to 1:00 p.m. EST.</ENT>
                    </ROW>
                </GPOTABLE>
                <P>The meeting is open to the public and will be conducted via WebEx.</P>
                <P>The purpose of the Committee is to provide advice to the Secretary of VA with respect to the administration of benefits by VA for services to Veterans' families, caregivers and survivors.</P>
                <P>On June 3, 2024, the agenda will include opening remarks from the Executive Sponsor, Veterans Health Administration (VHA) and the Committee Chair. The primary purpose of this meeting is to finalize the Committee's report and/or recommendations to the Secretary of VA.</P>
                <P>
                    The public are invited to attend in listening-mode. The chat function will be disabled. Due to the limited time for this meeting, there will be no public comments. However, individuals wishing to submit written comments may send them to 
                    <E T="03">VHA12CSPFAC@va.gov</E>
                     before Wednesday, May 29, 2024.
                </P>
                <P>
                    All attending should register at the following link: 
                    <E T="03">https://veteransaffairs.webex.com/weblink/register/r0bd23443e38ea0cd101657e56e5c5fff.</E>
                     Once registered, an email with the link for the June 3rd Webinar will be sent to your inbox (Note: also check Junk Mail Folder for an email from 
                    <E T="03">messenger@webex.com</E>
                    ). Anyone seeking additional information should contact Dr. Betty Moseley Brown, at 
                    <E T="03">Betty.MoseleyBrown@va.gov.</E>
                </P>
                <SIG>
                    <DATED>Dated: May 9, 2024.</DATED>
                    <NAME>Jelessa M. Burney,</NAME>
                    <TITLE>Federal Advisory Committee Management Officer.</TITLE>
                </SIG>
            </PREAMB>
            <FRDOC>[FR Doc. 2024-10514 Filed 5-13-24; 8:45 am]</FRDOC>
            <BILCOD>BILLING CODE P</BILCOD>
        </NOTICE>
    </NOTICES>
    <VOL>89</VOL>
    <NO>94</NO>
    <DATE>Tuesday, May 14, 2024</DATE>
    <UNITNAME>Presidential Documents</UNITNAME>
    <PRESDOCS>
        <PRESDOCU>
            <PROCLA>
                <TITLE3>Title 3—</TITLE3>
                <PRES>
                    The President
                    <PRTPAGE P="41881"/>
                </PRES>
                <PROC>Proclamation 10753 of May 9, 2024</PROC>
                <HD SOURCE="HED">Military Spouse Appreciation Day, 2024</HD>
                <PRES>By the President of the United States of America</PRES>
                <PROC>A Proclamation</PROC>
                <FP>Today, we honor the nearly one million military spouses for their service and sacrifice for our Nation. They are resilient. They are courageous. Like our service members, they make our country stronger.</FP>
                <FP>Through long tours, frequent moves, and constant demands, these men and women remain unwavering, representing the very best of our American spirit. They step up to care for their fellow military families and friends during deployments, often singlehandedly doing the job of two parents. They make incredible contributions to our country and communities, even as they shoulder the unique demands of military life. They exude patience and selflessness during uncertainty and unpredictability. In ways big and small, military spouses answer the call to serve every day—acting as both the backbone of their families and the steel spine of our Nation.</FP>
                <FP>We owe them. As a Nation, we have only one truly sacred obligation: to prepare those we send into harm's way and to care for them and their families while they are deployed and when they come home. That is why, last year, I signed an Executive Order that established the most comprehensive set of administrative actions in our country's history to support the economic security of military and veteran spouses, caregivers, and survivors. It directs all Federal agencies to do more to retain military spouses through flexible policies, enables spouses to seek advice on overseas employment issues through military legal assistance offices for the first time, and helps military spouses maintain their careers—including by improving access to quality, dependable, and affordable child care.</FP>
                <FP>My Administration has also expanded the Military Parental Leave Program, ensuring that service members have the time they need with their families after a child's birth, adoption, or placement in long-term foster care. Through the First Lady's Joining Forces initiative, we are working with employers to create more flexible, transferable, and remote job opportunities for military spouses so they can balance the demands of military life while building sustainable, long-term careers. We are working to ensure that military spouses and families have access to health and wellness resources.</FP>
                <FP>The English poet John Milton once wrote: “They also serve who only stand and wait.” Today and every day, let us come together to thank our military spouses. Let us honor their courage and commitment. Let us continue to meet the sacred obligation we bear to them and all those who wear the uniform. May God bless our military spouses, and may God protect our troops.</FP>
                <FP>NOW, THEREFORE, I, JOSEPH R. BIDEN JR., President of the United States of America, by virtue of the authority vested in me by the Constitution and the laws of the United States, do hereby proclaim May 10, 2024, as Military Spouse Appreciation Day. I call upon the people of the United States to honor military spouses with appropriate ceremonies and activities.</FP>
                <PRTPAGE P="41882"/>
                <FP>IN WITNESS WHEREOF, I have hereunto set my hand this ninth day of May, in the year of our Lord two thousand twenty-four, and of the Independence of the United States of America the two hundred and forty-eighth.</FP>
                <GPH SPAN="1" DEEP="80" HTYPE="RIGHT">
                    <GID>BIDEN.EPS</GID>
                </GPH>
                <PSIG> </PSIG>
                <FRDOC>[FR Doc. 2024-10639 </FRDOC>
                <FILED>Filed 5-13-24; 8:45 am]</FILED>
                <BILCOD>Billing code 3395-F4-P</BILCOD>
            </PROCLA>
        </PRESDOCU>
    </PRESDOCS>
    <VOL>89</VOL>
    <NO>94</NO>
    <DATE>Tuesday, May 14, 2024</DATE>
    <UNITNAME>Rules and Regulations</UNITNAME>
    <NEWPART>
        <PTITLE>
            <PRTPAGE P="42061"/>
            <PARTNO>Part II </PARTNO>
            <AGENCY TYPE="P">Environmental Protection Agency</AGENCY>
            <CFR>40 CFR Part 98</CFR>
            <TITLE>Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Final Rule</TITLE>
        </PTITLE>
        <RULES>
            <RULE>
                <PREAMB>
                    <PRTPAGE P="42062"/>
                    <AGENCY TYPE="S">ENVIRONMENTAL PROTECTION AGENCY</AGENCY>
                    <CFR>40 CFR Part 98</CFR>
                    <DEPDOC>[EPA-HQ-OAR-2023-0234; FRL-10246-02-OAR]</DEPDOC>
                    <RIN>RIN 2060-AV83</RIN>
                    <SUBJECT>Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems</SUBJECT>
                    <AGY>
                        <HD SOURCE="HED">AGENCY:</HD>
                        <P>Environmental Protection Agency (EPA).</P>
                    </AGY>
                    <ACT>
                        <HD SOURCE="HED">ACTION:</HD>
                        <P>Final rule.</P>
                    </ACT>
                    <SUM>
                        <HD SOURCE="HED">SUMMARY:</HD>
                        <P>The Environmental Protection Agency (EPA) is amending requirements that apply to the petroleum and natural gas systems source category of the Greenhouse Gas Reporting Rule to ensure that reporting is based on empirical data, accurately reflects total methane emissions and waste emissions from applicable facilities, and allows owners and operators of applicable facilities to submit empirical emissions data that appropriately demonstrate the extent to which a charge is owed under the Waste Emissions Charge. The EPA is also amending certain requirements that apply to the general provisions, general stationary fuel combustion, and petroleum and natural gas systems source categories of the Greenhouse Gas Reporting Rule to improve calculation, monitoring, and reporting of greenhouse gas data for petroleum and natural gas systems facilities. This action also establishes and amends confidentiality determinations for the reporting of certain data elements to be added or substantially revised in these amendments.</P>
                    </SUM>
                    <EFFDATE>
                        <HD SOURCE="HED">DATES:</HD>
                        <P>This rule is effective January 1, 2025, except for § 98.233 (amendatory instruction 12), § 98.236 (amendatory instruction 16), and § 98.238 (amendatory instruction 19) which are effective July 15, 2024. The incorporation by reference of certain material listed in this final rule is approved by the Director of the Federal Register as of January 1, 2025.</P>
                    </EFFDATE>
                    <ADD>
                        <HD SOURCE="HED">ADDRESSES:</HD>
                        <P>
                            The EPA has established a docket for this action under Docket ID. No. EPA-HQ-OAR-2023-0234. All documents in the docket are listed in the 
                            <E T="03">https://www.regulations.gov</E>
                             index. Although listed in the index, some information is not publicly available, 
                            <E T="03">e.g.,</E>
                             confidential business information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the internet and will be publicly available only in hard copy. Publicly available docket materials are available either electronically in 
                            <E T="03">https://www.regulations.gov</E>
                             or in hard copy at the EPA Docket Center, 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.
                        </P>
                    </ADD>
                    <FURINF>
                        <HD SOURCE="HED">FOR FURTHER INFORMATION CONTACT:</HD>
                        <P>
                            Jennifer Bohman, Climate Change Division, Office of Atmospheric Programs (MC-6207A), Environmental Protection Agency, 1200 Pennsylvania Ave. NW, Washington, DC 20460; telephone number: (202) 343-9548; email address: 
                            <E T="03">GHGReporting@epa.gov.</E>
                             For technical information, please go to the Greenhouse Gas Reporting Program (GHGRP) website, 
                            <E T="03">https://www.epa.gov/ghgreporting.</E>
                             To submit a question, select Help Center, followed by “Contact Us.”
                        </P>
                        <P>
                            <E T="03">World Wide Web (WWW).</E>
                             In addition to being available in the docket, an electronic copy of this final rule will also be available through the WWW. Following the Administrator's signature, a copy of this final rule will be posted on the EPA's GHGRP website at 
                            <E T="03">https://www.epa.gov/ghgreporting.</E>
                        </P>
                    </FURINF>
                </PREAMB>
                <SUPLINF>
                    <HD SOURCE="HED">SUPPLEMENTARY INFORMATION:</HD>
                    <P/>
                    <P>
                        <E T="03">Regulated entities.</E>
                         These final revisions affect certain entities that must submit annual greenhouse gas (GHG) reports under the GHGRP (40 CFR part 98). These are amendments to existing regulations and will affect owners or operators of petroleum and natural gas systems that directly emit GHGs. Regulated categories and entities include, but are not limited to, those listed in table 1 of this preamble:
                    </P>
                    <GPH SPAN="3" DEEP="166">
                        <GID>ER14MY24.000</GID>
                    </GPH>
                    <P>
                        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. This table lists the types of facilities that the EPA is now aware could potentially 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 will be affected by this action, you should carefully examine the applicability criteria found in 40 CFR part 98, subpart A (General Provisions) and 40 CFR part 98, subpart W (Petroleum and Natural Gas Systems). If you have questions regarding the applicability of this action to a particular facility, consult the person listed in the 
                        <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                         section.
                    </P>
                    <P>
                        <E T="03">Acronyms and Abbreviations.</E>
                         The following acronyms and abbreviations are used in this document.
                    </P>
                    <EXTRACT>
                        <FP SOURCE="FP-1">AGR acid gas removal unit</FP>
                        <FP SOURCE="FP-1">AMLD Advanced Mobile Leak Detection</FP>
                        <FP SOURCE="FP-1">
                            API American Petroleum Institute
                            <PRTPAGE P="42063"/>
                        </FP>
                        <FP SOURCE="FP-1">ASTM American Society for Testing and Materials</FP>
                        <FP SOURCE="FP-1">AVO audio, visual, and olfactory</FP>
                        <FP SOURCE="FP-1">BOEM U.S. Bureau of Ocean Energy Management</FP>
                        <FP SOURCE="FP-1">BRE Bryan Research &amp; Engineering</FP>
                        <FP SOURCE="FP-1">BSER best system of emissions reduction</FP>
                        <FP SOURCE="FP-1">Btu/scf British thermal units per standard cubic foot</FP>
                        <FP SOURCE="FP-1">CAA Clean Air Act</FP>
                        <FP SOURCE="FP-1">CBI confidential business information</FP>
                        <FP SOURCE="FP-1">CE combustion efficiency</FP>
                        <FP SOURCE="FP-1">CEMS continuous emissions monitoring system</FP>
                        <FP SOURCE="FP-1">CenSARA Central States Air Resources Agency</FP>
                        <FP SOURCE="FP-1">CFR Code of Federal Regulations</FP>
                        <FP SOURCE="FP-1">
                            CH
                            <E T="52">4</E>
                             methane
                        </FP>
                        <FP SOURCE="FP-1">
                            CO
                            <E T="52">2</E>
                             carbon dioxide
                        </FP>
                        <FP SOURCE="FP-1">
                            CO
                            <E T="52">2</E>
                            e carbon dioxide equivalent
                        </FP>
                        <FP SOURCE="FP-1">CRR cost-to-revenue ratio</FP>
                        <FP SOURCE="FP-1">DE destruction efficiency</FP>
                        <FP SOURCE="FP-1">DI&amp;M directed inspection and maintenance</FP>
                        <FP SOURCE="FP-1">DOE Department of Energy (DOE)</FP>
                        <FP SOURCE="FP-1">DRE destruction and removal efficiency</FP>
                        <FP SOURCE="FP-1">e-GGRT electronic Greenhouse Gas Reporting Tool</FP>
                        <FP SOURCE="FP-1">EG emission guidelines</FP>
                        <FP SOURCE="FP-1">EIA U.S. Energy Information Administration</FP>
                        <FP SOURCE="FP-1">EOR enhanced oil recovery</FP>
                        <FP SOURCE="FP-1">EPA U.S. Environmental Protection Agency</FP>
                        <FP SOURCE="FP-1">FAQ frequently asked question</FP>
                        <FP SOURCE="FP-1">FLIGHT Facility Level Information on Greenhouse gases Tool</FP>
                        <FP SOURCE="FP-1">FR Federal Register</FP>
                        <FP SOURCE="FP-1">FTIR Fourier transform infrared</FP>
                        <FP SOURCE="FP-1">GHG greenhouse gas</FP>
                        <FP SOURCE="FP-1">GHGRP Greenhouse Gas Reporting Program</FP>
                        <FP SOURCE="FP-1">GOR gas to oil ratio</FP>
                        <FP SOURCE="FP-1">gpm gallons per minute</FP>
                        <FP SOURCE="FP-1">GRI Gas Research Institute</FP>
                        <FP SOURCE="FP-1">GT gas turbines</FP>
                        <FP SOURCE="FP-1">HHV higher heating value</FP>
                        <FP SOURCE="FP-1">ICR information collection request</FP>
                        <FP SOURCE="FP-1">ID identification</FP>
                        <FP SOURCE="FP-1">IRA Inflation Reduction Act of 2022</FP>
                        <FP SOURCE="FP-1">IVT Inputs Verification Tool</FP>
                        <FP SOURCE="FP-1">kg/hr kilograms per hour</FP>
                        <FP SOURCE="FP-1">LDAR leak detection and repair</FP>
                        <FP SOURCE="FP-1">LDC local distribution company</FP>
                        <FP SOURCE="FP-1">LNG liquefied natural gas</FP>
                        <FP SOURCE="FP-1">m meters</FP>
                        <FP SOURCE="FP-1">MDEA methyl diethanolamine</FP>
                        <FP SOURCE="FP-1">MEA monoethanolamine</FP>
                        <FP SOURCE="FP-1">MMBtu/hr million British thermal units per hour</FP>
                        <FP SOURCE="FP-1">MMscf million standard cubic feet</FP>
                        <FP SOURCE="FP-1">mt metric tons</FP>
                        <FP SOURCE="FP-1">
                            mtCO
                            <E T="52">2</E>
                            e metric tons carbon dioxide equivalent
                        </FP>
                        <FP SOURCE="FP-1">
                            N
                            <E T="52">2</E>
                            O nitrous oxide
                        </FP>
                        <FP SOURCE="FP-1">NAICS North American Industry Classification System</FP>
                        <FP SOURCE="FP-1">NGLs natural gas liquids</FP>
                        <FP SOURCE="FP-1">NRU nitrogen recovery unit</FP>
                        <FP SOURCE="FP-1">NSPS new source performance standards</FP>
                        <FP SOURCE="FP-1">NYSERDA New York State Energy Research and Development Authority</FP>
                        <FP SOURCE="FP-1">O&amp;M operation and maintenance</FP>
                        <FP SOURCE="FP-1">OCS AQS Outer Continental Shelf Air Quality System</FP>
                        <FP SOURCE="FP-1">OEL open-ended line</FP>
                        <FP SOURCE="FP-1">OEM original equipment manufacturer</FP>
                        <FP SOURCE="FP-1">OGI optical gas imaging</FP>
                        <FP SOURCE="FP-1">OMB Office of Management and Budget</FP>
                        <FP SOURCE="FP-1">OTM other test method</FP>
                        <FP SOURCE="FP-1">PBI proprietary business information</FP>
                        <FP SOURCE="FP-1">PHMSA U.S. Pipeline and Hazardous Materials Safety Administration</FP>
                        <FP SOURCE="FP-1">ppm parts per million</FP>
                        <FP SOURCE="FP-1">ppmv parts per million by volume</FP>
                        <FP SOURCE="FP-1">PRA Paperwork Reduction Act</FP>
                        <FP SOURCE="FP-1">PRD pressure relief device</FP>
                        <FP SOURCE="FP-1">psig pounds per square inch gauge</FP>
                        <FP SOURCE="FP-1">PTE potential to emit</FP>
                        <FP SOURCE="FP-1">RFA Regulatory Flexibility Act</FP>
                        <FP SOURCE="FP-1">RFI Request for Information</FP>
                        <FP SOURCE="FP-1">RICE reciprocating internal combustion engines</FP>
                        <FP SOURCE="FP-1">RY reporting year</FP>
                        <FP SOURCE="FP-1">SCADA supervisory control and data acquisition</FP>
                        <FP SOURCE="FP-1">scf standard cubic feet</FP>
                        <FP SOURCE="FP-1">scf/hr/device standard cubic feet per hour per device</FP>
                        <FP SOURCE="FP-1">TCEQ Texas Commission on Environmental Quality</FP>
                        <FP SOURCE="FP-1">THC total hydrocarbon</FP>
                        <FP SOURCE="FP-1">TOC total organic carbon</FP>
                        <FP SOURCE="FP-1">TSD technical support document</FP>
                        <FP SOURCE="FP-1">U.S. United States</FP>
                        <FP SOURCE="FP-1">UMRA Unfunded Mandates Reform Act of 1995</FP>
                        <FP SOURCE="FP-1">VISR Video Imaging Spectro-Radiometry</FP>
                        <FP SOURCE="FP-1">VOC volatile organic compound(s)</FP>
                        <FP SOURCE="FP-1">WEC waste emissions charge</FP>
                        <FP SOURCE="FP-1">WWW World Wide Web</FP>
                    </EXTRACT>
                    <HD SOURCE="HD1">Table of Contents</HD>
                    <EXTRACT>
                        <FP SOURCE="FP-1">I. Background</FP>
                        <FP SOURCE="FP1-2">A. How is this preamble organized?</FP>
                        <FP SOURCE="FP1-2">B. Executive Summary</FP>
                        <FP SOURCE="FP1-2">C. Background on This Final Rule</FP>
                        <FP SOURCE="FP1-2">D. Legal Authority</FP>
                        <FP SOURCE="FP1-2">E. Relationship to Other Clean Air Act Section 136 Actions</FP>
                        <FP SOURCE="FP1-2">F. Relationship to Clean Air Act Section 111</FP>
                        <FP SOURCE="FP-1">II. Overview and Rationale for Final Amendments to 40 CFR Part 98, Subpart W</FP>
                        <FP SOURCE="FP1-2">A. Revisions To Address Potential Gaps in Reporting of Emissions Data for Specific Sectors</FP>
                        <FP SOURCE="FP1-2">B. Revisions To Add New Emissions Calculation Methodologies or Improve Existing Emissions Calculation Methodologies</FP>
                        <FP SOURCE="FP1-2">C. Revisions to Reporting Requirements To Improve Verification and Transparency of the Data Collected</FP>
                        <FP SOURCE="FP1-2">D. Technical Amendments, Clarifications, and Corrections</FP>
                        <FP SOURCE="FP-1">III. Final Amendments to Part 98 and Summary of Comments and Responses</FP>
                        <FP SOURCE="FP1-2">A. General and Applicability Amendments</FP>
                        <FP SOURCE="FP1-2">B. Other Large Release Events</FP>
                        <FP SOURCE="FP1-2">C. New and Additional Emission Sources</FP>
                        <FP SOURCE="FP1-2">D. Reporting for the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting Industry Segments</FP>
                        <FP SOURCE="FP1-2">E. Natural Gas Pneumatic Device Venting and Natural Gas Driven Pneumatic Pump Venting</FP>
                        <FP SOURCE="FP1-2">F. Acid Gas Removal Unit Vents</FP>
                        <FP SOURCE="FP1-2">G. Dehydrator Vents</FP>
                        <FP SOURCE="FP1-2">H. Liquids Unloading</FP>
                        <FP SOURCE="FP1-2">I. Gas Well Completions and Workovers With Hydraulic Fracturing</FP>
                        <FP SOURCE="FP1-2">J. Blowdown Vent Stacks</FP>
                        <FP SOURCE="FP1-2">K. Atmospheric Storage Tanks</FP>
                        <FP SOURCE="FP1-2">L. Flared Transmission Storage Tank Vent Emissions</FP>
                        <FP SOURCE="FP1-2">M. Associated Gas Venting and Flaring</FP>
                        <FP SOURCE="FP1-2">N. Flare Stack Emissions</FP>
                        <FP SOURCE="FP1-2">O. Compressors</FP>
                        <FP SOURCE="FP1-2">P. Equipment Leak Surveys</FP>
                        <FP SOURCE="FP1-2">Q. Equipment Leaks by Population Count</FP>
                        <FP SOURCE="FP1-2">R. Offshore Production</FP>
                        <FP SOURCE="FP1-2">S. Combustion Equipment</FP>
                        <FP SOURCE="FP1-2">T. Leak Detection and Measurement Methods</FP>
                        <FP SOURCE="FP1-2">U. Industry Segment-Specific Throughput Quantity Reporting</FP>
                        <FP SOURCE="FP1-2">V. Other Final Minor Revisions or Clarifications</FP>
                        <FP SOURCE="FP-1">IV. Effective Date of the Final Amendments</FP>
                        <FP SOURCE="FP1-2">A. Amendments That Are Effective on January 1, 2025</FP>
                        <FP SOURCE="FP1-2">B. Amendments That Are Effective July 15, 2024</FP>
                        <FP SOURCE="FP-1">V. Final Confidentiality and Reporting Determinations for Certain Data Reporting Elements</FP>
                        <FP SOURCE="FP1-2">A. EPA's Approach To Assess Data Elements</FP>
                        <FP SOURCE="FP1-2">B. Final Confidentiality Determinations and Emissions Data Designations</FP>
                        <FP SOURCE="FP1-2">C. Final Reporting Determinations for Inputs to Emission Equations</FP>
                        <FP SOURCE="FP-1">VI. Impacts of the Final Amendments</FP>
                        <FP SOURCE="FP1-2">A. Cost Analysis</FP>
                        <FP SOURCE="FP1-2">B. Cost-to-Revenue Ratio Analysis</FP>
                        <FP SOURCE="FP-1">VII. Statutory and Executive Order Reviews</FP>
                        <FP SOURCE="FP1-2">A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review</FP>
                        <FP SOURCE="FP1-2">B. Paperwork Reduction Act (PRA)</FP>
                        <FP SOURCE="FP1-2">C. Regulatory Flexibility Act (RFA)</FP>
                        <FP SOURCE="FP1-2">D. Unfunded Mandates Reform Act (UMRA)</FP>
                        <FP SOURCE="FP1-2">E. Executive Order 13132: Federalism</FP>
                        <FP SOURCE="FP1-2">F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments</FP>
                        <FP SOURCE="FP1-2">G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks</FP>
                        <FP SOURCE="FP1-2">H. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use</FP>
                        <FP SOURCE="FP1-2">I. National Technology Transfer and Advancement Act and 1 CFR part 51</FP>
                        <FP SOURCE="FP1-2">J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations</FP>
                        <FP SOURCE="FP1-2">K. Congressional Review Act (CRA)</FP>
                        <FP SOURCE="FP1-2">L. Judicial Review</FP>
                        <FP SOURCE="FP1-2">M. Determination Under CAA Section 307(d)</FP>
                        <FP SOURCE="FP1-2">N. Severability</FP>
                    </EXTRACT>
                    <HD SOURCE="HD1">I. Background</HD>
                    <HD SOURCE="HD2">A. How is this preamble organized?</HD>
                    <P>
                        The first section of this preamble contains background information on the August 1, 2023 proposed amendments (88 FR 50282, hereafter referred to as “2023 Subpart W Proposal”) and on this final rule, as well as a summary of the final revisions. This section also discusses the EPA's legal authority under the Clean Air Act (CAA) to 
                        <PRTPAGE P="42064"/>
                        promulgate (including subsequent amendments to) the Greenhouse Gas Reporting Rule, codified at 40 CFR part 98 (hereafter referred to as “part 98”), generally and 40 CFR part 98, subpart W (hereafter referred to as “subpart W”) in particular. This section also discusses the EPA's legal authority to make confidentiality determinations for new or revised data elements corresponding to these amendments or for existing data elements for which the EPA is finalizing a new determination. Section II. of this preamble describes the types of amendments included in this final rulemaking and includes the rationale for each type of change. Section III. of this preamble contains detailed information on the revisions to 40 CFR part 98, subpart A (General Provisions), subpart C (General Stationary Fuel Combustion Sources) and subpart W. Section IV. of this preamble explains the effective date of the final revisions and how the revisions are required to be implemented in reporting year (RY) 2024 and RY2025 reports. Section V. of this preamble discusses the final confidentiality determinations for new or substantially revised (
                        <E T="03">i.e.,</E>
                         requiring additional or different data to be reported) data reporting elements, as well as for certain existing data elements for which the EPA is finalizing a new determination. Section VI. of this preamble discusses the impacts of the amendments. Finally, section VII. of this preamble describes the statutory and Executive Order requirements applicable to this action.
                    </P>
                    <HD SOURCE="HD2">B. Executive Summary</HD>
                    <P>
                        In August 2022, Congress passed, and President Biden signed, the Inflation Reduction Act of 2022 (IRA) into law. Section 60113 of the IRA amended the CAA by adding section 136, “Methane Emissions and Waste Reduction Incentive Program for Petroleum and Natural Gas Systems.” CAA section 136(c), “Waste Emissions Charge,” directs the Administrator to impose and collect a charge on methane (CH
                        <E T="52">4</E>
                        ) emissions that exceed statutorily specified waste emissions thresholds from owners or operators of applicable facilities that report more than 25,000 metric tons carbon dioxide equivalent (mtCO
                        <E T="52">2</E>
                        e) pursuant to the Greenhouse Gas Reporting Rule's requirements for the petroleum and natural gas systems source category (codified as subpart W in the EPA's Greenhouse Gas Reporting Rule regulations). Further, CAA section 136(h) requires that the EPA shall, within two years after the date of enactment of section 60113 of the IRA, revise the requirements of subpart W to ensure the reporting under subpart W (and corresponding waste emissions charges under CAA section 136) is based on empirical data, accurately reflects the total CH
                        <E T="52">4</E>
                         emissions (and waste emissions) from the applicable facilities, and allow owners and operators of applicable facilities to submit empirical emissions data, in a manner to be prescribed by the Administrator, to demonstrate the extent to which a charge is owed under CAA section 136.
                    </P>
                    <P>
                        On August 1, 2023, the EPA proposed revisions to subpart W consistent with the authority and directives set forth in CAA section 136(h) as well as the EPA's authority under CAA section 114 in the 2023 Subpart W Proposal. The EPA proposed revisions to include reporting of additional emissions or emissions sources to address potential gaps in the total CH
                        <E T="52">4</E>
                         emissions reported by facilities to subpart W. The EPA also proposed several revisions to add new or revise existing calculation methodologies to improve the accuracy of reported emissions, incorporate additional empirical data and to allow owners and operators of applicable facilities to submit empirical emissions data that could appropriately demonstrate the extent to which a charge is owed in future implementation of CAA section 136, as directed by CAA section 136(h). For example, the EPA proposed new calculation methodologies for equipment leaks and natural gas pneumatic devices to allow for the use of direct measurement. The EPA also proposed several revisions to existing reporting requirements to collect data that would improve verification of reported data, ensure accurate reporting of emissions, and improve the transparency of reported data. For example, the EPA proposed to disaggregate reporting requirements within the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments, with most emissions and activity data for Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting being disaggregated to at least the well-pad site and gathering and boosting site level, respectively. The EPA also proposed other technical amendments, corrections, and clarifications that would improve understanding of the rule. These revisions primarily included revisions of requirements to better reflect the EPA's intent or editorial changes. The 2023 Subpart W Proposal also indicated that the EPA would be undertaking one or more separate actions in the future to implement the remainder of CAA section 136.
                    </P>
                    <P>The EPA is finalizing revisions to part 98 included in the 2023 Subpart W Proposal, with some changes made after consideration of public comments. The final amendments include new reporting requirements with some revisions from what was proposed for other large release events, produced water storage tanks, nitrogen removal units, drilling mud degassing, and crankcase venting. The final amendments expand the applicability of certain emission sources to new industry segments as proposed. The final amendments also include new calculation methods, with some revisions to those proposed, that provide measurement or monitoring survey options, including for the calculation of emissions from equipment leaks, combustion slip, crankcase venting, associated gas, compressors, natural gas pneumatic devices, and equipment leaks from components at transmission company interconnect metering and regulating stations, to allow reporters to use appropriate empirical data for these emission sources as an alternative to population emission factors. We are also revising calculation methods, with some revisions based on comments received, to improve the accuracy or clarity of the existing calculation methods. This action also finalizes confidentiality determinations for the reporting of data elements added or substantially revised in these final amendments, and for certain existing data elements for which no confidentiality determination has been made previously or for which the EPA proposed to revise the existing determination.</P>
                    <P>
                        In some cases, and as further described in section III. of this preamble, the EPA is not taking final action in this final rule on certain proposed revisions included in the 2023 Subpart W Proposal. For example, after review of comments received in response to the proposed requirements for reporters in the Onshore Petroleum and Natural Gas Production, Natural Gas Distribution, Onshore Petroleum and Natural Gas Gathering and Boosting, and Onshore Natural Gas Transmission Pipeline industry segments that have ownership changes in subpart A, the EPA is not taking action at this time on the revisions to subpart A regarding responsibilities for revisions to reports submitted in the years before the ownership transactions. In consideration of the relationship between revisions to annual reports for prior years and implementation requirements for CAA section 136(c) 
                        <PRTPAGE P="42065"/>
                        proposed on January 26, 2024 (89 FR 5318) (hereafter referred to as the “2024 WEC Proposal”), the EPA intends to consider those proposed revisions in coordination with the development of the WEC final rule and take action, if finalized, on these requirements at the same time. In some cases, we are not taking final action at this time on certain revisions to the calculation or monitoring methodologies that would have revised how data are collected. For example, after review and consideration of the comments received in response to the proposed requirements for flares, we are not finalizing requirements to use continuous flow monitors or continuous parametric monitoring and continuous composition analyzers or quarterly sampling to determine flow and composition, respectively, of gas routed to flares. In several cases, we are also not taking final action at this time on proposed revisions to add reporting requirements. For example, we are not finalizing certain proposed reporting requirements for other large release events when the reporter receives a third-party notification because all Super-Emitter Program notifications will come from the EPA and the EPA will already have the information proposed to be reported.
                    </P>
                    <P>
                        Some of the final amendments, particularly those that allow reporters to choose from additional calculation methodologies and submit empirical emissions data will be effective immediately as optional methodologies. These amendments will apply to reports submitted by current reporters that are submitted in calendar year 2025 and subsequent years (
                        <E T="03">i.e.,</E>
                         starting with reports submitted for RY2024 by March 31, 2025). The remaining final amendments will become effective on January 1, 2025. Those final revisions, which apply to both existing and new reporters, will be first implemented for reports prepared for RY2025 and submitted by March 31, 2026. Reporters who are newly subject to the rule will be required to implement all requirements to collect data, including any required monitoring and recordkeeping, on January 1, 2025.
                    </P>
                    <P>These final amendments are anticipated to result in an overall increase in burden for part 98 reporters in cases where the amendments expand current applicability, add or revise reporting requirements, or require additional emissions data to be reported. The final revisions will affect approximately 567 new reporters and 2,510 existing reporters. The incremental implementation labor costs are $169.4 million per year over the next three years (RY2025 through RY2027), for a total of $508.3 million for the three years. There is an additional incremental annualized burden of $14.1 million for operation and maintenance (O&amp;M) costs in RY2025 and in each subsequent year (RY2026 and RY2027), which reflects changes to monitoring for 2,510 existing reporters and the 567 additional reporters.</P>
                    <P>
                        Labor costs increased from $41.4 million per year at proposal to $169.4 million per year at final, based in part on consideration of comments received on the estimated labor hours needed to comply with these amendments at proposal. As detailed in section VI.A. of this preamble and the 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule,</E>
                         those labor hour estimates have been revised, leading to higher labor costs.
                    </P>
                    <HD SOURCE="HD2">C. Background on This Final Rule</HD>
                    <P>
                        This final action builds on previous part 98 rulemakings. The Greenhouse Gas Reporting Rule was published in the 
                        <E T="04">Federal Register</E>
                         (FR) on October 30, 2009 (74 FR 56260) (hereafter referred to as the 2009 Final Rule). The 2009 Final Rule became effective on December 29, 2009, and requires reporting of GHGs from various facilities and suppliers, consistent with the 2008 Consolidated Appropriations Act.
                        <SU>1</SU>
                        <FTREF/>
                         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 rulemaking 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 (75 FR 18608; April 12, 2010), and a subsequent final rulemaking 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 “2010 Final Rule”). Following promulgation, the EPA finalized several technical and clarifying amendments to subpart W (76 FR 22825, April 25, 2011; 76 FR 53057, August 25, 2011; 76 FR 59533, September 27, 2011; 76 FR 73866, November 29, 2011; 76 FR 80554, December 23, 2011; 77 FR 48072, August 13, 2012; 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; 80 FR 64262, October 22, 2015; and 81 FR 86490, November 30, 2016). These amendments generally added or revised requirements in subpart W, including revisions that were intended to improve quality, clarity, and consistency across the calculation, monitoring, and data reporting requirements, and to finalize confidentiality and reporting determinations for data elements reported under the subpart.
                    </P>
                    <FTNT>
                        <P>
                            <SU>1</SU>
                             Consolidated Appropriations Act, 2008, Public Law 110-161, 121 Stat. 1844, 2128.
                        </P>
                    </FTNT>
                    <P>More recently, the EPA proposed amendments to subpart W on June 21, 2022 (87 FR 36920) (hereafter referred to as the “2022 Proposed Rule”), including technical amendments to improve the quality and consistency of the data collected under the rule and resolve data gaps, amendments to streamline and improve implementation, and revisions to provide additional flexibility in the calculation methods and monitoring requirements for some emission sources. The 2022 Proposed Rule was developed prior to the enactment of the Inflation Reduction Act, which was signed into law on August 16, 2022, and its direction in CAA section 136(h) to revise subpart W. Consequently, in developing the 2023 Subpart W Proposal, the EPA considered the proposed amendments to subpart W from the 2022 Proposed Rule as well as the concerns and information submitted by commenters in response to that proposal. In the 2023 Subpart W Proposal, the EPA proposed to revise the subpart W provisions, including both (1) updates to the proposed revisions to subpart W that were in the 2022 Proposed Rule as well as (2) additional proposed revisions to comply with CAA section 136(h). The preamble to the 2023 Subpart W Proposal explained that the EPA did not intend to finalize the revisions to subpart W that were proposed in the 2022 Proposed Rule and that the final amendments to subpart W would include consideration of public comments on the 2023 Subpart W Proposal.</P>
                    <P>
                        Additionally, the EPA opened a non-regulatory docket on November 4, 2022, and issued a Request for Information (RFI) seeking public input to inform program design related to CAA section 136.
                        <SU>2</SU>
                        <FTREF/>
                         As part of this request, the EPA sought input on revisions that should be considered related to subpart W. The comment period closed on January 18, 2023.
                    </P>
                    <FTNT>
                        <P>
                            <SU>2</SU>
                             Docket ID No. EPA-HQ-OAR-2022-0875.
                        </P>
                    </FTNT>
                    <P>
                        The EPA is finalizing amendments and confidentiality determinations in this action, with certain changes from 
                        <PRTPAGE P="42066"/>
                        the 2023 Subpart W Proposal following consideration of comments submitted and based on the EPA's updated assessment. The revisions reflect the EPA's efforts to improve calculation, monitoring, and reporting of greenhouse gas data for petroleum and natural gas systems facilities and to ensure that reporting is based on empirical data, accurately reflects total methane emissions and waste emissions from applicable facilities, and allows owners and operators of applicable facilities to submit empirical emissions data that appropriately demonstrate the extent to which a charge is owed under the Waste Emissions Charge. Responses to major comments submitted on the proposed amendments from the 2023 Subpart W Proposal considered in the development of this final rule can be found in section III. of this preamble. Documentation of all comments received as well as the EPA's responses can be found in the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule,</E>
                         available in the docket to this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).
                    </P>
                    <P>
                        While this final rule complies with and is consistent with directives in CAA section 136(h), this final rule does not address implementation of other portions of CAA section 136 (section 60113 of the Inflation Reduction Act), “Methane Emissions and Waste Reduction Incentive Program for Petroleum and Natural Gas Systems.” The EPA noted in the preamble to the 2023 Subpart W Proposal that we intend to issue one or more separate actions to implement other requirements of CAA section 136, which could include revisions to certain requirements of subpart W for implementation purposes. Subsequently, the EPA published the 2024 WEC Proposal to implement CAA section 136(c), “Waste Emissions Charge,” or “WEC,” on January 26, 2024 (89 FR 5318).
                        <SU>3</SU>
                        <FTREF/>
                    </P>
                    <FTNT>
                        <P>
                            <SU>3</SU>
                             CAA section 136(c), “Waste Emissions Charge,” directs the Administrator to impose and collect a charge on methane (CH
                            <E T="52">4</E>
                            ) emissions that exceed statutorily specified waste emissions thresholds from an owner or operator of an applicable facility that reports more than 25,000 metric tons carbon dioxide equivalent pursuant to the Greenhouse Gas Reporting Rule's requirements for the petroleum and natural gas systems source category (codified as subpart W in the EPA's Greenhouse Gas Reporting Rule regulations).
                        </P>
                    </FTNT>
                    <HD SOURCE="HD2">D. Legal Authority</HD>
                    <P>
                        The EPA is finalizing these rule amendments under its existing CAA authority provided in CAA section 114 and under its newly established authority provided in CAA section 136, as applicable. As noted in the preamble to the proposed rule for this rulemaking and in the preamble to the 2009 Final Rule (74 FR 56264, October 30, 2009), the EPA has consistently applied its authority under CAA section 114(a)(1) for over a decade 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 of a variety of CAA provisions. Thus, when promulgating amendments to the Greenhouse Gas Reporting Rule (40 CFR part 98), the EPA has assessed the reasonableness of requiring the information to be provided and explained how the data are relevant to the EPA's ability to carry out the provisions of the CAA. See the preambles to the proposed Greenhouse Gas Reporting Rule (74 FR 16448, April 10, 2009) and the 2009 Final Rule for further information. Additionally, in enacting CAA section 136, Congress implicitly recognized the EPA's appropriate use of CAA authority in promulgating the GHGRP. As noted in section I.B. of this preamble, the provisions of CAA section 136 reference and are in part based on the Greenhouse Gas Reporting Rule requirements under subpart W for the petroleum and natural gas systems source category and require further revisions to subpart W for purposes of supporting implementation of section 136. Under CAA section 136(h), Congress directed the Administrator to revise the requirements of subpart W to ensure that reporting of CH
                        <E T="52">4</E>
                         emissions under subpart W (and corresponding waste emissions charges under CAA section 136) is based on empirical data, accurately reflects the total CH
                        <E T="52">4</E>
                         emissions (and waste emissions) from applicable facilities, and allows owners and operators to submit empirical emissions data, in a manner prescribed by the Administrator, to demonstrate the extent to which a charge is owed under CAA section 136. Under CAA section 136, an “applicable facility” is a facility within nine of the ten industry segments subject to subpart W, as currently defined in 40 CFR 98.230 (excluding natural gas distribution). The revisions being finalized are consistent with these directives, ensuring that (1) reporting of methane emissions under subpart W are based on empirical data, (2) accurately reflect total methane emissions (and waste emissions) and (3) allow owners and operators to submit appropriate empirical data. The EPA appropriately applied its authority in this rulemaking in a manner consistent with CAA section 114 and the directives under CAA section 136. See section II. of this preamble for discussion of the rationale for these revisions, which includes that they can be used to support carrying out a range of future climate change policies and regulations under the CAA, including but not limited to information relevant to carrying out CAA section 136, provisions involving research, evaluating and setting standards, endangerment determinations, or informing EPA non-regulatory programs under the CAA, and see also section III. of this preamble and the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule,</E>
                         available in the docket to this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234), for further detail on the revisions and their supporting rationale.
                    </P>
                    <P>The Administrator has determined that this action is subject to the provisions of section 307(d) of the CAA (see also section VII.M. of this preamble). Section 307(d) contains a set of procedures relating to the issuance and review of certain CAA rules.</P>
                    <P>In addition, pursuant to sections 114, 301, and 307 of the CAA, the EPA is publishing final confidentiality determinations for the new or substantially revised data elements required by these amendments. Section 114(c) requires that the EPA make information obtained under section 114 available to the public, except for information (excluding emission data) that qualifies for confidential treatment.</P>
                    <HD SOURCE="HD2">E. Relationship to Other Clean Air Act Section 136 Actions</HD>
                    <P>
                        The IRA adds authorities under CAA section 136 to reduce CH
                        <E T="52">4</E>
                         emissions from the oil and gas sector. It accomplishes this in multiple ways. First, it provides incentives for CH
                        <E T="52">4</E>
                         mitigation and monitoring. Second, it establishes a waste emissions charge for applicable facilities that exceed statutorily specified thresholds that vary by industry segment and are determined by the amount of natural gas or oil sent to sale. Third, CAA section 136(h) requires the EPA to revise subpart W. The first and second listed aspects of CAA section 136 are outside the scope of this rulemaking.
                    </P>
                    <P>
                        CAA section 136 provides $1.55 billion in incentives for CH
                        <E T="52">4</E>
                         mitigation and monitoring, including through grants, rebates, contracts, loans, and other activities. Of these funds, at least $700 million is allocated to activities at 
                        <PRTPAGE P="42067"/>
                        marginal conventional wells. There are several potential uses of funds. Use of funds can include financial and technical assistance to owners and operators of applicable facilities to prepare and submit GHG reports under subpart W. Financial assistance can also be provided for CH
                        <E T="52">4</E>
                         emissions monitoring authorized under CAA section 103 subsections (a) through (c). Additionally, financial and technical assistance can be provided to: reduce CH
                        <E T="52">4</E>
                         and other GHG emissions from petroleum and natural gas systems, including to mitigate legacy air pollution from petroleum and natural gas systems; improve climate resilience of communities and petroleum and natural gas systems; improve and deploy industrial equipment and processes that reduce CH
                        <E T="52">4</E>
                         and other GHG emissions and waste; support innovation in reducing CH
                        <E T="52">4</E>
                         and other GHG emissions and waste from petroleum and natural gas systems; permanently shut in and plug wells on non-Federal land; and mitigate health effects of CH
                        <E T="52">4</E>
                         and other GHG emissions and legacy air pollution from petroleum and natural gas systems in low-income and disadvantaged communities, and support environmental restoration.
                    </P>
                    <P>
                        The EPA has partnered with the Department of Energy (DOE) to administer financial assistance under the Methane Emission Reduction Program. In 2023, DOE announced and conditionally awarded $350 million in funds to fourteen states to measure and reduce methane emissions from low-producing conventional wells.
                        <SU>4</SU>
                        <FTREF/>
                         In February 2024, the EPA and DOE announced intent to open a competitive funding opportunity to a broader range of applicants to reduce and monitor emissions from the oil and gas industry.
                        <SU>5</SU>
                        <FTREF/>
                    </P>
                    <FTNT>
                        <P>
                            <SU>4</SU>
                             U.S. Environmental Protection Agency. (2023, December 15). Biden-Harris Administration Announces $350 Million to 14 States to Reduce Methane Emissions from Oil and Gas Sector as Part of Investing in America Agenda [Press Release]. 
                            <E T="03">https://www.epa.gov/newsreleases/biden-harris-administration-announces-350-million-14-states-reduce-methane-emissions.</E>
                             Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>5</SU>
                             U.S. Environmental Protection Agency. (2024, February 9). EPA and DOE announce intent to fund projects to reduce methane emissions from the oil and natural gas sectors as part of President Biden's Investing in America agenda [Press Release]. 
                            <E T="03">https://www.epa.gov/newsreleases/epa-and-doe-announce-intent-fund-projects-reduce-methane-emissions-oil-and-natural-gas.</E>
                             Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        The EPA and DOE are moving expeditiously to implement the incentives for CH
                        <E T="52">4</E>
                         mitigation and monitoring and anticipate making announcements regarding next steps; however, as noted, those steps are outside the scope of this rulemaking. As relevant data become available from the funded activities, the EPA will consider how they can be used to improve reporting under subpart W.
                    </P>
                    <P>
                        CAA section 136(c) provides that the Administrator shall impose and collect a charge on CH
                        <E T="52">4</E>
                         emissions that exceed an applicable waste emissions threshold under CAA section 136(f) from an owner or operator of an applicable facility that reports more than 25,000 mtCO
                        <E T="52">2</E>
                        e per year pursuant to subpart W. CAA section 136 provides various flexibilities and exemptions relating to the waste emissions charge. The EPA proposed to add 40 CFR part 99 to implement the WEC in the 2024 WEC Proposal and has provided an opportunity for public comment on that proposal; therefore, as noted, implementation of the WEC is outside the scope of this rulemaking.
                    </P>
                    <P>As noted earlier, CAA section 136(h) requires revisions to subpart W. The purpose of this final action is to meet directives set forth in CAA section 136(h) and to amend certain requirements that apply to the general provisions, general stationary fuel combustion, and petroleum and natural gas systems source categories of the Greenhouse Gas Reporting Rule to improve the calculation, monitoring, and reporting of greenhouse gas data for petroleum and natural gas systems facilities consistent with the EPA's authority.</P>
                    <HD SOURCE="HD2">F. Relationship to Clean Air Act Section 111</HD>
                    <P>
                        The EPA had also identified areas where additional revisions to part 98 would better align subpart W requirements with recently promulgated requirements in 40 CFR part 60 and part 62, allow facilities to use a consistent method to demonstrate compliance with multiple EPA programs (and thereby limit burden), and improve the emission calculations reported under subpart W. On November 15, 2021 (86 FR 63110), the EPA proposed under CAA section 111(b) standards of performance for certain new, reconstructed, and modified oil and natural gas sources (40 CFR part 60, subpart OOOOb) (hereafter referred to as “NSPS OOOOb”), as well as emissions guidelines under CAA section 111(d) for certain existing oil and natural gas sources (40 CFR part 60, subpart OOOOc) (hereafter referred to as “EG OOOOc”) (the sources affected by these two proposed subparts are collectively referred to in this preamble as “affected sources”). On December 6, 2022, the EPA issued a supplemental proposal to update, strengthen and expand the standards proposed on November 15, 2021 (87 FR 74702). On March 8, 2024, the final NSPS OOOOb and EG OOOOc rule published in the 
                        <E T="04">Federal Register</E>
                         (89 FR 16820). While the standards in NSPS OOOOb will directly apply to new, reconstructed, and modified sources, the final EG OOOOc does not impose binding requirements directly on sources; rather it contains guidelines, including presumptive standards, for states to follow in developing, submitting, and implementing plans to establish standards of performance to limit GHGs (in the form of CH
                        <E T="52">4</E>
                         limitations) from existing oil and gas sources within their own states. If a state does not submit a plan to the EPA for approval in response to the final emission guidelines, or if the EPA disapproves a state's plan, then the EPA must establish a Federal plan. In addition, a Federal plan could apply to sources located on Tribal lands where the tribe does not request approval to develop a tribal implementation plan similar to a state plan. Once the Administrator approves a state plan under CAA section 111(d), the plan is codified in 40 CFR part 62 (Approval and Promulgation of State Plans for Designated Facilities and Pollutants) within the relevant subpart for that state. 40 CFR part 62 also includes all Federal plans promulgated pursuant to CAA section 111(d). Therefore, rather than referencing the presumptive standards in EG OOOOc, which do not directly apply to sources, the final amendments to subpart W reference 40 CFR part 62.
                    </P>
                    <P>We are finalizing revisions to certain requirements in subpart W relative to the requirements finalized for NSPS OOOOb and the presumptive standards in EG OOOOc (which will inform the standards to be developed and codified at 40 CFR part 62). The final amendments in this rule will allow facilities to use a consistent method to demonstrate compliance with multiple EPA programs. These final standards will limit burden for subpart W facilities with affected sources that are also required to comply with the NSPS OOOOb or a state or Federal plan in 40 CFR part 62 implementing EG OOOOc by allowing them to use data derived from the implementation of the NSPS OOOOb to calculate emissions for the GHGRP rather than requiring the use of different monitoring methods.</P>
                    <HD SOURCE="HD1">II. Overview and Rationale for Final Amendments to 40 CFR Part 98, Subpart W</HD>
                    <P>
                        As discussed in section I. of this preamble, in August 2022, Congress 
                        <PRTPAGE P="42068"/>
                        passed, and President Biden signed, the IRA into law. Section 60113 of the IRA amended the CAA by adding section 136, “Methane Emissions and Waste Reduction Incentive Program for Petroleum and Natural Gas Systems.” CAA section 136(h) requires that the EPA shall, within two years of the enactment of that section of the IRA, revise the requirements of subpart W to ensure the reporting under that subpart and calculation of charges under CAA section 136(e) and (f) are based on empirical data, accurately reflect the total CH
                        <E T="52">4</E>
                         emissions and waste emissions from the applicable facilities, and allow owners and operators of applicable facilities to submit empirical emissions data, in a manner prescribed by the Administrator, to demonstrate the extent to which a charge is owed. CAA section 136(d) defines the term “applicable facility” as a facility within the following industry segments as defined in subpart W: offshore petroleum and natural gas production, onshore petroleum and natural gas production, onshore natural gas processing, onshore gas transmission compression, underground natural gas storage, liquefied natural gas storage, liquefied natural gas import and export equipment, onshore petroleum and natural gas gathering and boosting, and onshore natural gas transmission pipeline.
                    </P>
                    <P>
                        Empirical data can be defined as data that are collected by observation and experiment. There are many forms of empirical data that can be used to quantify GHG emissions. For purposes of this action, the EPA interprets empirical data to mean data that are collected by conducting observations and experiments that could be used to accurately calculate emissions at a facility, including direct emissions measurements, monitoring of CH
                        <E T="52">4</E>
                         emissions (
                        <E T="03">e.g.,</E>
                         leak surveys) or measurement of associated parameters (
                        <E T="03">e.g.,</E>
                         flow rate, pressure), and published data. The EPA reviewed available empirical data methods for accuracy and appropriateness for calculating annual unit or facility-level GHG emissions. The review included both the evaluation of technologies and methodologies already incorporated in subpart W for measuring and reporting annual source- and facility-level GHG emissions and the evaluation of the accuracy of potential alternative technologies and methodologies, with a focus on CH
                        <E T="52">4</E>
                         emissions due to the directive in CAA section 136(h). The EPA also reviewed technologies and methodologies suggested by commenters during the public comment period for the 2023 Subpart W Proposal.
                    </P>
                    <P>
                        Currently, subpart W specifies emission source types to be reported for each industry segment and provides methodologies to calculate emissions from each source type, which are then summed to generate the total subpart W emissions for the facility. Current calculation methods can be grouped into five categories: (1) direct emissions measurement; (2) combination of measurement and engineering calculations; (3) engineering calculations; (4) leak detection and use of a leaker emission factor; and (5) population count and population emission factors. Subpart W emission factors (both population and leaker emission factors) include both those developed from published empirical data and those developed from site-specific data collected by the reporting facility. The EPA developed the current subpart W monitoring and reporting requirements to use the most appropriate monitoring and calculation methods, considering both the accuracy of the emissions calculated by the proposed method and the size of the emission source based on the methods and data available at the time of the applicable rule promulgation. Considering the directives set forth in CAA section 136, the EPA re-evaluated the existing methodologies to determine if they are likely to accurately reflect CH
                        <E T="52">4</E>
                         and waste emissions at an individual facility, whether the existing methodologies used empirical data, and whether the existing methodologies should be modified or replaced or if additional optional calculation methods were available and appropriate and should be added to meet CAA section 136 directives. Even in cases where the EPA determined that an existing method that is not based on direct measurement or emission monitoring provides a reasonably accurate calculation of emissions for a facility, we also reviewed whether an appropriate direct emission measurement or emission monitoring method could be added to subpart W, if one was not already available, to give owners and operators the opportunity to submit empirical data. For example, intermittent bleed pneumatic devices are designed to vent during actuation only, but these devices are known to often malfunction and operate incorrectly, which causes them to release gas to the atmosphere when idle, leading to high degree of variance in emissions from pneumatic devices between facilities (see the technical support document 
                        <E T="03">Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for Data Elements Under the Greenhouse Gas Reporting Rule; Final Rule—Petroleum and Natural Gas Systems,</E>
                         hereafter referred to as the “final subpart W TSD,” available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234, for more information). For this example, the final amendments add several new optional calculation methods to allow reporters to account for the variability. The EPA also evaluated whether there were gaps in the emission source types reporting CH
                        <E T="52">4</E>
                         emissions under subpart W and whether there were methodologies available to calculate those emissions.
                    </P>
                    <P>The final amendments include:</P>
                    <P>
                        • Revisions to expand reporting to include new emission sources, in order to accurately reflect total CH
                        <E T="52">4</E>
                         emissions reported to the GHGRP.
                    </P>
                    <P>• Revisions to add emissions calculation methodologies to expand options to allow owners and operators to submit empirical emissions data and improve the accuracy of reported emission data, including to expand options to allow owners and operators to submit empirical emissions data where the EPA determined appropriate methods were available.</P>
                    <P>• Revisions to refine existing emissions calculation methodologies to reflect an improved understanding of emissions, to incorporate additional empirical data or to incorporate more recent research on GHG emissions to improve the accuracy of reported emission data.</P>
                    <P>The EPA has also identified additional areas where revisions to part 98 will improve the EPA's ability to verify the accuracy of reported emissions and improve data transparency and alignment with other EPA programs and regulations. The EPA also identified areas where additional data or revised data elements may be necessary for future implementation of the Waste Emissions Charge under CAA section 136. The final revisions include:</P>
                    <P>• Revisions to report emissions and certain associated data from emission sources at facilities in the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments at the site level or well level instead of at the basin level, sub-basin level, or county level.</P>
                    <P>• Addition of data elements related to emissions from plugged wells.</P>
                    <P>• Addition or clarification of throughput-related data elements for subpart W industry segments.</P>
                    <P>
                        • Revisions to data elements or recordkeeping where the current 
                        <PRTPAGE P="42069"/>
                        requirements are redundant or alternative data are more appropriate for verification of emission data.
                    </P>
                    <P>• Revisions that provide additional information for reporters to better or more fully understand their compliance obligations, revisions that emphasize the EPA's intent for requirements that reporters appear to have previously misinterpreted to ensure that accurate data are being collected, and editorial corrections or harmonizing changes that will improve the public's understanding of the rule.</P>
                    <P>Sections II.A. through II.D. of this preamble describe the above changes in more detail and provide the EPA's rationale for the changes included in each category. Additional details for the specific amendments for each subpart are included in section III. of this preamble.</P>
                    <HD SOURCE="HD2">A. Revisions To Address Potential Gaps in Reporting of Emissions Data for Specific Sectors</HD>
                    <P>
                        We are finalizing several amendments to include reporting of additional emissions or emissions sources to address potential gaps in the total CH
                        <E T="52">4</E>
                         emissions reported per facility to subpart W. These final amendments ensure that the reporting under subpart W accurately reflects the total CH
                        <E T="52">4</E>
                         emissions and waste emissions from applicable facilities, as directed by CAA section 136(h). In particular, based on recent analyses such as those conducted for the annual 
                        <E T="03">Inventory of U.S. Greenhouse Gas Emissions and Sinks</E>
                         (U.S. GHG Inventory), and data newly available from atmospheric observations, we have become aware of potentially significant sources of emissions for which there are no current emission estimation methods or reporting requirements within part 98. For subpart W, we are finalizing the addition of calculation methodologies and requirements to report GHG emissions for several additional sources. We are adding a new emissions source, referred to as “other large release events,” to capture abnormal emission events that are not accurately accounted for using existing methods in subpart W. This additional source covers events such as storage wellhead leaks, well blowouts,
                        <SU>6</SU>
                        <FTREF/>
                         and other large, atypical release events and will apply to all types of facilities subject to subpart W. Reporters will calculate GHG emissions using measurement data or engineering estimates of the amount of gas released and using measurement data, if available, or process knowledge (best available data) to estimate the composition of the released gas. We are also finalizing the addition of calculation methodologies and requirements to report GHG emissions for several other new emission sources, including nitrogen removal units, produced water tanks, mud degassing, and crankcase venting. None of these sources are currently accounted for in subpart W, and the EPA is adding them because they are likely to have a meaningful impact on reported total facility CH
                        <E T="52">4</E>
                         emissions. We are also finalizing revisions to the existing methodologies and adding new measurement-based methodologies, consistent with section II.B. of this preamble, for determining combustion emissions from RICE and GT to account for combustion slip, which is not currently accounted for under the existing calculation methodologies for combustion emissions. We are also finalizing requirements to report existing emission sources for certain subpart W industry segments under additional industry segments. For example, we are requiring liquefied natural gas (LNG) import/export facilities to begin calculating and reporting emissions from acid gas removal unit (AGR) vents. Additional details of these types of final changes may be found in section III. of this preamble.
                    </P>
                    <FTNT>
                        <P>
                            <SU>6</SU>
                             We are finalizing as proposed the provision to define a well blowout in 40 CFR 98.238 as a complete loss of well control for a long duration of time resulting in an emissions release.
                        </P>
                    </FTNT>
                    <HD SOURCE="HD2">B. Revisions To Add New Emissions Calculation Methodologies or Improve Existing Emissions Calculation Methodologies</HD>
                    <P>
                        We are finalizing several revisions to add new or revise existing calculation methodologies to improve the accuracy of emissions data reported to the GHGRP, incorporate additional empirical data, and to allow owners and operators of applicable facilities to submit empirical emissions data that appropriately demonstrate the extent to which a charge is owed in future implementation of CAA section 136, as directed by CAA section 136(h). Subpart W specifies emission source types to be reported for each industry segment and provides methodologies to calculate emissions from each source type, which are then summed to generate the total subpart W emissions for the facility. Considering the directives set forth in CAA section 136, the EPA re-evaluated the existing methodologies for each source to determine if they are likely to accurately reflect CH
                        <E T="52">4</E>
                         and waste emissions at an individual facility, whether the existing methodologies used empirical data (
                        <E T="03">e.g.,</E>
                         direct emissions measurements or monitoring of CH
                        <E T="52">4</E>
                         emissions; measurement of associated parameters), and whether the existing methodologies should be modified or replaced or if new optional calculation methodologies should be added to meet CAA section 136 directives. A summary list of the final emissions sources to be reported with the corresponding monitoring and emissions calculation methods is available in the final subpart W TSD, available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234. Many sources in subpart W already have or require calculation methodologies that use direct emission measurement, including AGR vents, large reciprocating compressor rod packing vents, large compressor blowdown vent valve leaks, and large compressor blowdown vent (unit isolation valve leaks), the latter three when leakage is detected via screening. In these final amendments, the EPA is finalizing the addition of new calculation methodologies to allow for the use of direct measurement, including for the calculation of emissions from equipment leaks, combustion slip, crankcase venting, associated gas, compressors, natural gas pneumatic devices, and equipment leaks from components at transmission company interconnect metering and regulating stations. The EPA is also finalizing new calculation methodologies to allow for the development of facility-specific emission factors for equipment leaks based on data collected from direct measurement at the facility. The EPA is also finalizing the option to use advanced technologies to measure data that are inputs to emissions calculations for flares and completions and workovers with hydraulic fracturing. These final amendments will provide owners and operators the opportunity to submit appropriate empirical data in their subpart W annual reports. We also reviewed whether some optional calculation methodologies would be appropriate to allow in RY2024, so that owners and operators would have the opportunity to submit appropriate empirical data in line with existing subpart W. As discussed in section IV. of this preamble, we are finalizing the addition of a number of new optional calculation methodologies that are relevant to existing subpart W sources effective July 15, 2024.
                    </P>
                    <P>
                        Similar to the 2016 amendments to align subpart W requirements with certain requirements in 40 CFR part 60, subpart OOOOa (hereafter referred to as “NSPS OOOOa”) (81 FR 86500, 
                        <PRTPAGE P="42070"/>
                        November 30, 2016), we are also finalizing revisions to certain requirements in subpart W relative to the requirements finalized for NSPS OOOOb and the presumptive standards in EG OOOOc (which will inform the standards to be developed and codified at 40 CFR part 62). As in the 2016 rule, the final amendments also allow facilities to use a consistent method to demonstrate compliance with multiple EPA programs. These final standards will limit burden for subpart W facilities with affected sources that are also required to comply with the NSPS OOOOb or a state or Federal plan in 40 CFR part 62 implementing EG OOOOc by allowing them to use data derived from the implementation of the NSPS OOOOb to calculate emissions for the GHGRP rather than requiring the use of different monitoring methods. Consistent with that goal, the final amendments to subpart W reference the final version of the method(s) in the NSPS OOOOb and EG OOOOc. These amendments also improve the emission calculations reported under the GHGRP by requiring the use of facility-collected measurement or survey data to calculate emissions where available and appropriate. Specifically, we are finalizing amendments to the subpart W calculation methodologies for atmospheric pressure storage tanks, flares, centrifugal and reciprocating compressors, and equipment leak surveys related to the final NSPS OOOOb and presumptive standards in EG OOOOc, and we are finalizing new reporting requirements for “other large release events” as defined in subpart W that reference the NSPS OOOOb and approved state plans or applicable Federal plan in 40 CFR part 62. These final amendments are described in sections III.B., N., O., and P. of this preamble; the effective dates of these final amendments are discussed in section IV. of this preamble. As reflected in section IV. of this preamble, the provisions of these final amendments that reference the NSPS OOOOb and approved state plans or applicable Federal plan in 40 CFR part 62 do not apply to individual reporters unless and until their emission sources are required to comply with either the final NSPS OOOOb or an approved state plan or applicable Federal plan in 40 CFR part 62. In the meantime, reporters have the option to comply with the calculation methodologies that are required for sources subject to NSPS OOOOb or 40 CFR part 62, or they may comply instead with the applicable provisions of subpart W that apply to sources not subject to NSPS OOOOb or 40 CFR part 62. For example, for flare sources, subpart W facilities have the option to comply with the flare monitoring requirements in NSPS OOOOb even if the source is not yet subject to or will not be subject to those provisions. For the “other large release events” source category, emissions from other large release events are required to be calculated and reported starting in Reporting Year (RY) 2025; the requirements to calculate and report these emissions are not dependent on whether a source is subject to NSPS OOOOb or 40 CFR part 62. The specific changes that we are finalizing, as described in this section, are described in detail in section III. of this preamble.
                    </P>
                    <P>We are also finalizing several revisions to modify calculation equations to incorporate refinements to methodologies based on an improved understanding of emission sources. In some cases, we have become aware of discrepancies between assumptions in the current emission estimation methods and the processes or activities conducted at specific facilities, where the revisions will reduce reporter errors. In other cases, we are revising the emissions estimation methodologies to incorporate recent studies on GHG emissions or formation that reflect updates to scientific understanding of GHG emissions sources. The final amendments will improve the quality and accuracy of the data collected under the GHGRP.</P>
                    <P>
                        We are also finalizing revisions to several existing calculation methodologies to incorporate empirical data obtained at the facility. Emissions can be reliably calculated for sources such as atmospheric storage tanks and glycol dehydrators using standard engineering first principle methods such as those available in API 4697 E&amp;P Tanks 
                        <SU>7</SU>
                        <FTREF/>
                         and GRI-GLYCalc
                        <E T="51">TM</E>
                         
                        <SU>8</SU>
                        <FTREF/>
                         when based on actual operating conditions. Using such software also addresses safety concerns that are associated with direct emissions measurement from these sources in certain circumstances. For example, sometimes the temperature of the emissions stream for glycol dehydrator vent stacks is too high for operators to safely measure emissions. Currently these methods in subpart W allow for use of best available data for all inputs to the model. However, the EPA has noted that in some cases, such as with reporting of emissions from some dehydrators, the data used to calculate emissions are not based on actual operating conditions but instead based on “worst-case scenarios” or other estimates. In these final amendments, for large glycol dehydrators and AGRs, we are requiring that certain input parameters be based on actual measurements at the unit level in order to ensure that emissions calculations are based on actual operating conditions and to improve the accuracy of the reported emissions for these sources.
                    </P>
                    <FTNT>
                        <P>
                            <SU>7</SU>
                             E&amp;P Tanks v3.0 software and the user guide (Publication 4697) formerly available from the American Petroleum Institute (API) website.
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>8</SU>
                             GRI-GLYCalc
                            <E T="51">TM</E>
                             software available from Gas Technology Institute website 
                            <E T="03">(https://sales.gastechnology.org/)</E>
                        </P>
                    </FTNT>
                    <P>In order to improve the accuracy of the data collected under the GHGRP, we are finalizing revisions to emission factors where improved measurement data has become available or we have received additional information from stakeholders. Some of the calculation methodologies provided in the GHGRP rely on the use of emission factors that are based on published empirical data. Default emission factors based on representative empirical data can provide a reasonably accurate estimate of facility-level emissions. The final rule includes revisions to emission factors for a number of emission source types where we have received or identified updated, representative measurement data.</P>
                    <P>We are finalizing updated emission factors for natural gas pneumatic devices, equipment leaks from natural gas distribution sources (including pipeline mains and services, below grade transmission-distribution transfer stations, and below grade metering-regulating stations) and equipment at onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities, and compressors at onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities in subpart W. The revised emission factors are more representative of GHG emissions sources and will improve the overall accuracy of the emission data collected under the GHGRP. Additional details of these types of final revisions may be found in section III. of this preamble.</P>
                    <P>
                        As noted in section II.A. of this preamble, we are adding a new emissions source, referred to as “other large release events,” to capture abnormal emission events that are not accurately accounted for using existing methods in subpart W. Under these provisions in this final rule, the EPA is also finalizing the inclusion of emissions from other large emissions events and super-emitters in the subpart W reporting program. This addition will directly address the concerns identified by a multitude of studies about the 
                        <PRTPAGE P="42071"/>
                        contribution of super-emitters to total emissions and help to ensure the completeness and accuracy of emissions reporting data. Advanced measurement approaches that have demonstrated their ability to detect, attribute the source at least to site-level, and accurately quantify emission rates of such events are a central feature of the finalized changes. Some advanced measurement approaches have a demonstrated ability to provide data useful for quantifying emissions from very large, distinct emission events, such as production well blowouts. In the U.S. GHG Inventory, the EPA has already incorporated emissions estimates developed from such approaches to calculate emissions from well blowouts.
                        <FTREF/>
                        <SU>9</SU>
                         In this final rule, we are requiring facilities to consider notifications of super-emitter emissions event under the super-emitter provisions of NSPS OOOO/OOOOa/OOOOb at 40 CFR 60.5371, 60.5371a, and 60.5371b or the applicable approved state plan or applicable Federal plan and calculate the associated emissions when they exceed the final threshold of 100 kg/hr CH4 if they are not already appropriately accounted for under another source category in subpart W. We expect that under the final methodology for other large release events, data from some advanced measurement approaches, including data derived from equipment leak and fugitive emissions monitoring using advanced screening methods conducted under NSPS OOOOb or the applicable approved state plan or applicable Federal plan in 40 CFR part 62, in combination with other empirical data, could be used by reporters to calculate the total emissions from these events and/or estimate duration of such an event.
                    </P>
                    <FTNT>
                        <P>
                            <SU>9</SU>
                             U.S. EPA. 
                            <E T="03">Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2020: Updates for Anomalous Events including Well Blowout and Well Release Emissions.</E>
                             April 2022. Available at 
                            <E T="03">https://www.epa.gov/system/files/documents/2022-04/2022_ghgi_update_-_blowouts.pdf</E>
                             and in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>The EPA received numerous comments requesting that the EPA allow for the use of advanced technologies to quantify emissions from other emission sources in subpart W beyond “other large release events.” In response, we reviewed advanced measurement approaches that utilize information from satellite, aerial, drone, vehicle, and stationary platforms to detect and/or quantify methane emissions from petroleum and natural gas systems at different spatial and temporal scales for their potential use in estimating emissions of specific sources for the purposes of subpart W reporting. Advanced technologies have been a focus for research and emission monitoring strategies, and several technologies have progressed in recent years to provide valuable CH4 emission data. The spatial and temporal resolution of emission estimates varies widely, however, depending on the technology and platform.</P>
                    <P>
                        Two general categories of advanced technologies were evaluated for their potential use in subpart W: remote sensing (
                        <E T="03">e.g.,</E>
                         satellite, aerial) and continuous monitoring systems, which typically use gas sensors and/or imaging coupled with proprietary algorithms to detect emissions and/or provide emission rates. Remote sensing approaches typically use aerial or satellite-deployed infrared spectroscopy to survey areas for methane emission plumes. For remote sensing technologies, the size of the area monitored is typically inversely related to the detection levels. Satellite remote sensing technologies are deployed at altitudes of 400 to 800 kilometers and currently have CH4 detection limits of approximately 50 to 25,000 kilograms per hour (kg/hr),
                        <FTREF/>
                        <SU>10</SU>
                         and high altitude remote sensing (by airplane) measure at altitudes of 168 to 12,000 meters (m) with current CH4 detection limits of approximately 1 to 50 kg/hr.
                        <FTREF/>
                        <SU>11</SU>
                         We find that existing remote sensing approaches are suitable to supplement the other requirements for periodic measurement and calculation of annual emissions for large discrete events, as they are capable of having suitable detection limits for the identification of the presence of large anomalous events. However, our assessment at this time is that existing remote sensing approaches currently are not able to appropriately estimate annual emissions from other sources under subpart W. Most remote sensing measurements are taken over limited durations (a few minutes to a few hours) typically during the daylight hours and limited to times when specific meteorological conditions exist (
                        <E T="03">e.g.,</E>
                         no cloud cover for satellites; specific atmospheric stability and wind speed ranges for aerial measurements). These direct measurement data taken at a particular moment in time may not be representative of the annual CH4 emissions from the facility, given that many emissions are episodic. If emissions are found during a limited duration sampling, that does not necessarily mean they are present for the entire year. And if emissions are not found during a limited duration sampling, that does not necessarily mean significant emissions are not occurring at other times. Extrapolating from limited measurements to an entire year therefore creates risk of either over or under counting actual emissions.
                    </P>
                    <FTNT>
                        <P>
                            <SU>10</SU>
                             See GHGSat. GHGSat Media Kit. (2021). Available at 
                            <E T="03">https://www.ghgsat.com/upload/misc/GHGSAT_MEDIAKIT_2021.pdf;</E>
                             Pandey, S., 
                            <E T="03">et al.</E>
                             “Satellite observations reveal extreme methane leakage from a natural gas well blowout.” 
                            <E T="03">Proceedings of the National Academy of Sciences,</E>
                             Vol. 116, no. 52. Pp. 26376-26381, December 16, 2019, available at 
                            <E T="03">https://doi.org/10.1073/pnas.1908712116;</E>
                             Jacob, D.J., 
                            <E T="03">et al.</E>
                             “Quantifying methane emissions from the global scale down to point sources using satellite observations of atmospheric methane.” 
                            <E T="03">Atmospheric Chemistry and Physics, Vol.</E>
                             22, Issue 14, pp. 9617-9646, July 29, 2022, available at 
                            <E T="03">https://doi.org/10.5194/acp-22-9617-2022;</E>
                             Anderson, V., 
                            <E T="03">et al.</E>
                             “Technological opportunities for sensing of the health effects of weather and climate change: a state-of-the-art-review.” 
                            <E T="03">International Journal of Biometeorology,</E>
                             Vol. 65, Issue 6, pp. 779-803, January 11, 2021, available at 
                            <E T="03">https://doi.org/10.1007/s00484-020-02063-z.</E>
                             The documents are also available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>11</SU>
                             See Conrad, B.M., Tyner, D.R. &amp; Johnson, M.R. “Robust probabilities of detection and quantification uncertainty for aerial methane detection: Examples for three airborne technologies.” 
                            <E T="03">Remote Sensing of Environment,</E>
                             Vol. 288, p. 113499, available at 
                            <E T="03">https://doi.org/10.1016/j.rse.2023.113499.</E>
                             2023; Duren, R.M., et al. “California's methane super-emitters.” 
                            <E T="03">Nature,</E>
                             Vol. 575, Issue 7781, pp. 180-184, available at 
                            <E T="03">https://doi.org/10.1038/s41586-019-1720-3.</E>
                             2019; Thorpe, A.K., 
                            <E T="03">et al.</E>
                             “Airborne DOAS retrievals of methane, carbon dioxide, and water vapor concentrations at high spatial resolution: application to AVIRIS-NG.” 
                            <E T="03">Atmos. Meas. Tech.,</E>
                             10, 3833-3850, available at 
                            <E T="03">https://doi.org/10.5194/amt-10-3833-2017.</E>
                             2017; Staebell, C., 
                            <E T="03">et al.</E>
                             “Spectral calibration of the MethaneAIR instrument.” 
                            <E T="03">Atmospheric Measurement Techniques,</E>
                             Vol. 14, Issue 5, pp. 3737-3753, available at 
                            <E T="03">https://doi.org/10.5194/amt-14-3737-2021.</E>
                             2021. The documents are also available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        Additionally, while advanced measurement methods based on remote sensing, including satellite and aerial methods, have proven their ability to identify and measure large emissions events, their detection limits may be too high to detect emissions from sources with relatively low emission rates.
                        <FTREF/>
                        <SU>12</SU>
                         The data provided by some of these technologies are at large spatial scales, with limited ability to disaggregate to the facility- or emission source-level and have high minimum detection limits. So while these technologies can provide very useful information about emissions during snapshots in time, and thus help to greatly improve the completeness and accuracy of emission reporting, with the current state of these technologies they generally cannot by themselves estimate annual emissions. 
                        <PRTPAGE P="42072"/>
                        Therefore, this rule finalizes allowing the use of these advanced measurement methods based on remote sensing to supplement the other requirements for periodic measurement and calculation of annual emissions for other large release events, as described in section III.B. of this preamble.
                    </P>
                    <FTNT>
                        <P>
                            <SU>12</SU>
                             Duren, 
                            <E T="03">et al.</E>
                             “California's methane super-emitters.” 
                            <E T="03">Nature,</E>
                             Vol. 575, Issue 7781, pp. 180-184, 2019. Available at 
                            <E T="03">https://doi.org/10.1038/s41586-019-1720-3</E>
                             and in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        Continuous monitoring systems, which typically use one or more stationary sensors and/or imagers located on or near sites to frequently detect and/or quantify anomalous emissions, can have significant value for detecting anomalous emissions but are less suitable for the annual quantification that is required for purposes of the Greenhouse Gas Reporting Program and satisfying Congress's directive in the Inflation Reduction Act. Although these systems may continuously collect methane concentration data, emissions data from monitored sites are not typically continuous because methane emission plumes may not reach sensors or visual images may not detect plumes under certain meteorological and operational conditions. Recent studies evaluating the performance of several continuous monitors have reported that these systems can provide valuable data for detecting anomalous emissions (and generally faster than survey methods) and determining event duration, but typically have high uncertainty in quantifying total emissions.
                        <FTREF/>
                        <SU>13</SU>
                         Therefore, we determined that continuous monitoring systems currently are not suitable for quantifying emissions for subpart W reporting on their own but may provide data on the duration of large release events. Further discussion of our review of advanced technologies is available in the final subpart W TSD, available in the docket for this rulemaking.
                    </P>
                    <FTNT>
                        <P>
                            <SU>13</SU>
                             See, 
                            <E T="03">e.g.,</E>
                             Bell, C., et al. “Performance of Continuous Emission Monitoring Solutions under a Single-Blind Controlled Testing Protocol.” 
                            <E T="03">Environ. Sci. Technol.</E>
                             2023, 57, 14, 5794-5805. Published March 28, 2023. 
                            <E T="03">https://doi.org/10.1021/acs.est.2c09235.</E>
                             Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>Based on our review, we are finalizing the use of advanced measurement data, including both remote sensing technologies and continuous monitoring systems, to help identify and quantify super-emitter and other large emissions events. Commenters also requested that the EPA allow for the adoption of advanced technologies without having to go through a new rulemaking process, similar to the technology verification programs developed under the NSPS OOOOb and EG OOOOc even though many commenters acknowledged that with the current state of advanced technologies, it is not possible to accurately quantify annual emissions at the individual source level, particularly at low emission rates as would be needed to accurately quantify many subpart W sources. However, for reasons discussed below, this final rule does not include a general provision to incorporate the use of advanced measurement approaches at this time except in certain cases, such as large release events. It is worth noting that the NSPS OOOOb and EG OOOOc (and the technologies that are verified under that program), are focused on detecting leaks or identifying anomalous emissions that exceed certain action levels, which is more straightforward than accurately quantifying source emission rates over annual time periods. Furthermore, the EPA is not aware of a standardized protocol to accurately extrapolate from either continuous or discrete remote sensing measurement data to an annual, facility-level emission total. At this point in time, there are still many outstanding research questions associated with how best to combine advanced measurement data (sometimes called “top-down” methods) with bottom-up methods in a way that avoids double counting of emissions, including how frequently measurements would need to be conducted to be considered reliable or representative of annual emissions for reporting purposes, and what emissions simulation modeling would be necessary to accurately estimate annual emissions. As described previously in this section, the different types of measurement data have a wide range of detection limits and spatial resolution, which makes converting point estimates to an annual emission estimate as required by and necessary for the purposes of the GHGRP subpart W difficult. Therefore, this final rule does not include a general provision to incorporate the use of advanced measurement approaches for sources at this time and instead specifically allows its use in certain appropriate cases, including for other large release events, due to the limitations described earlier in this section.</P>
                    <P>The EPA notes that advanced measurement approaches are rapidly evolving, and expects that these approaches will continue to improve over time. Advanced measurement approaches are currently being used to generate a range of valuable information on emissions sources in the oil and natural gas sector and have great promise for playing a greater role in subpart W emissions reporting as experience with using them to quantify emissions grows. We will continue to closely monitor developments in advanced monitoring technologies and measurement approaches and engage with experts and stakeholders on how they can be used in subpart W reporting.</P>
                    <P>
                        As these measurement approaches continue to develop, the EPA will, as appropriate, undertake notice-and-comment rulemaking to determine under what circumstances these approaches can be used for subpart W reporting of methane emissions, and how subpart W reporters can use these approaches to quantify annual emissions based on advanced technologies and the rapid evolution of such technologies. Given the wide variety of advanced measurement approaches and the methodological challenges described above, the EPA believes it is necessary to provide adequate notice and opportunity for comment on the use of advanced measurement approaches in order to incorporate such technologies into subpart W. We believe that such an approach is consistent with the historic implementation of the Greenhouse Gas Reporting Rule which has been revised over time to incorporate the latest data, updated scientific knowledge and additional measurement methods. In advance of such a rulemaking, the EPA intends to solicit input on the use of advanced measurement data and methods in subpart W through a request for information, workshop or white paper. We further intend to evaluate for potential future subpart W updates whether there are measurement approaches that could be used to estimate annual emissions for any source categories under subpart W or for facility-level emissions, what level of accuracy should be required for such use, and whether the development of standard protocols for estimating emissions from advanced measurement (either by the EPA or third-party organizations) could help inform this determination. We also intend to evaluate whether there are other appropriate uses of this data for the purposes of reporting under subpart W of the GHGRP, including for what types of emission sources and emission events and what specific measurement approaches use may be appropriate, especially in terms of spatial scale and minimum detection limits. We will also continue to evaluate how frequently measurements would need to be conducted to be considered reliable or representative of annual emissions for reporting purposes.
                        <PRTPAGE P="42073"/>
                    </P>
                    <HD SOURCE="HD2">C. Revisions to Reporting Requirements To Improve Verification and Transparency of the Data Collected</HD>
                    <P>The EPA is finalizing several revisions to existing reporting requirements to collect data that will improve verification of reported data and improve the transparency of the data collected. Data reported under the GHGRP undergo comprehensive verification review. This process identifies errors that result in the over- or under- statement of emissions that are reported from individual facilities and leads to their correction. As such, amendments that improve the verification process are supportive of the directive under CAA section 136(h) to ensure that reporting under subpart W accurately reflects total methane emissions. Additionally, such revisions will better enable the EPA to obtain data that is of sufficient quality and granularity that it can be used to support a range of future climate change policies and regulations under the CAA, including but not limited to information relevant to carrying out CAA section 136, provisions involving research, evaluating and setting standards, endangerment determinations, or informing EPA non-regulatory programs under the CAA.</P>
                    <P>The final revisions include changes to the level of reporting of aggregated emissions and activity data that will improve the process of emissions verification and the transparency and granularity of the data. For example, we are finalizing requirements for Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segment reporters to report emissions and associated activity data at the site level or well level instead of at the basin level, sub-basin level, or county level.</P>
                    <P>We are also finalizing additions or revisions to reporting requirements to better characterize the emissions for several emission sources. For example, we are collecting additional information from facilities with liquids unloadings to differentiate between manual and automated unloadings.</P>
                    <P>Other final revisions to the rule include changes that will better align reporting with the calculation methods in the rule. For example, we are finalizing revisions to reporting requirements related to atmospheric pressure fixed roof storage tanks receiving hydrocarbon liquids that follow the methodology specified in 40 CFR 98.233(j)(3) and equation W-15. The current calculation methodology uses population emission factors and the count of applicable separators, wells, or non-separator equipment to determine the annual total volumetric GHG emissions at standard conditions. The associated reporting requirements in existing 40 CFR 98.236(j)(2)(i)(E) and (F) require reporters to delineate the counts used in equation W-15. The current reporting requirements are inadvertently inconsistent with the language used in the calculation methodology and are seemingly not inclusive of all equipment to be included. Therefore, we are revising the reporting requirements to better align the requirement with the calculation methodology and streamline the requirements for all facilities reporting atmospheric storage tanks emissions using the methodology in 40 CFR 98.233(j)(3).</P>
                    <P>In some cases, we are finalizing the removal of duplicative reporting elements within or across GHGRP subparts to reduce data inconsistencies and reporting errors. For example, we are eliminating duplicative reporting between subpart NN (Suppliers of Natural Gas and Natural Gas Liquids) and subpart W where both subparts require similar data elements to be reported to the electronic Greenhouse Gas Reporting Tool (e-GGRT). For fractionators of natural gas liquids (NGLs), both subpart W (under the Onshore Natural Gas Processing segment) and subpart NN require reporting of the volume of natural gas received and the volume of NGLs received. For Local Distribution Companies (LDCs), both subpart W (under the Natural Gas Distribution segment) and subpart NN require reporting of the volume of natural gas received, volume placed into and out of storage each year, and volume transferred to other LDCs or to a pipeline as well as some other duplicative data. The final amendments limit the reporting of these data elements to facilities that do not report under subpart NN, thus removing the duplicative requirements from subpart W for facilities that report to both subparts. These data elements are not the throughputs that are proposed to be used for WEC calculations; see section III.U. of this preamble and the 2024 WEC Proposal for more information on those throughputs. This revision will improve the EPA's ability to verify the reported data across subparts.</P>
                    <HD SOURCE="HD2">D. Technical Amendments, Clarifications, and Corrections</HD>
                    <P>
                        We are finalizing other technical amendments, corrections, and clarifications that will improve understanding of the rule. These revisions primarily include revisions of requirements to better reflect the EPA's intent or editorial changes. Some of these changes result from consideration of questions raised by reporters through the GHGRP Help Desk or e-GGRT. In particular, we are finalizing amendments for several source types that will emphasize the original intent of certain rule requirements, such as reported data elements that have been misinterpreted by reporters. In several cases, the misinterpretation of these provisions may have resulted in reporting that is inconsistent with the rule requirements. The final clarifications will increase the likelihood that reporters will submit accurate reports the first time. For example, the EPA is finalizing revisions to the definition of variable “T
                        <E T="0732">t</E>
                        ” in existing equation W-1 (final equation W-1B) in 40 CFR 98.233 and the corresponding reporting requirements in final 40 CFR 98.236(b)(4)(ii)(D)(4), (b)(5)(i)(C)(2), and (b)(6)(ii) to use the term “in service (
                        <E T="03">i.e.,</E>
                         supplied with natural gas)” rather than “operational” or “operating.” This revision emphasizes the EPA's intent that the average number of hours used in equation W-1 (final equation W-1B) should be the number of hours that the devices of a particular type are in service (
                        <E T="03">i.e.,</E>
                         the devices are receiving a measurement signal and connected to a natural gas supply that is capable of actuating a valve or other device as needed). These final clarifications and corrections will also reduce the burden associated with reporting, data verification, and EPA review. Additional details of these types of final changes are discussed in section III. of this preamble.
                    </P>
                    <P>
                        We are also finalizing revisions to applicability provisions for certain industry segments and applicable calculation methods. For example, we are revising the definition of the Onshore Natural Gas Processing industry segment to remove the gas throughput threshold so that the applicable industry segment and calculation methods are defined from the beginning of the year. The current definition of the Onshore Natural Gas Processing industry segment includes processing plants that fractionate gas liquids and processing plants that do not fractionate gas liquids but have an annual average throughput of 25 million standard cubic feet (MMscf) per day or greater. Processing plants that do not fractionate gas liquids and have an annual average throughput of less than 25 MMscf per day may be part of a facility in the Onshore Petroleum and Natural Gas Gathering and Boosting 
                        <PRTPAGE P="42074"/>
                        industry segment. Processing plants that do not fractionate gas liquids and generally operate close to the 25 MMscf per day threshold do not know until the end of the year whether they will be above or below the threshold, so they must be prepared to report under whichever industry segment is ultimately applicable. Therefore, as discussed in greater detail in section III.A.3. of this preamble, we are revising the Onshore Natural Gas Processing industry segment definition in 40 CFR 98.230(a)(3) to remove the 25 MMscf per day threshold and more closely align subpart W with the definitions of natural gas processing in other rules (
                        <E T="03">e.g.,</E>
                         NSPS OOOOa). This revision to the Onshore Natural Gas Processing industry segment definition will better define whether a processing plant is classified as an Onshore Natural Gas Processing facility or as part of an Onshore Petroleum and Natural Gas Gathering and Boosting facility, and the applicable segment will no longer have the potential to change from one year to the next simply based on the facility throughput.
                    </P>
                    <P>Additional details of these types of final changes may be found in section III. of this preamble.</P>
                    <P>Other minor changes being finalized include correction edits to fix typos, minor clarifications such as adding a missing word, harmonizing changes to match other final revisions, reordering of paragraphs so that a larger number of paragraphs need not be renumbered, and others as reflected in the redline regulatory text in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).</P>
                    <HD SOURCE="HD1">III. Final Amendments to Part 98 and Summary of Comments and Responses</HD>
                    <P>
                        This section summarizes the specific substantive final amendments for subpart W (as well as subparts A and C), as generally described in section II. of this preamble. Major changes to the final rule as compared to the proposed revisions are identified in this section. The summary of the amendments in each section is followed by a summary of the major comments on those amendments and the EPA's responses to those comments. The document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule,</E>
                         available in the docket to this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234), contains the full text of all the comments on the 2023 Subpart W Proposal, including the major comments responded to in this preamble. All final amendments, including minor corrections and clarifications, are also reflected in the final redline regulatory text in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).
                    </P>
                    <P>Section III.A of this preamble describes amendments that affect reporting responsibility or applicability. Sections III.B through III.U of this preamble describe technical amendments that affect specific source types or industry segments. Section III.V of this preamble lists miscellaneous technical corrections and clarifications.</P>
                    <HD SOURCE="HD2">A. General and Applicability Amendments</HD>
                    <HD SOURCE="HD3">1. Ownership Transfer</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        We are finalizing amendments to specific provisions to subpart A that will apply in lieu of existing 40 CFR 98.4(h) for changes in the owner or operator of a facility in the four industry segments in subpart W (Petroleum and Natural Gas Systems) that have unique definitions of facility.
                        <FTREF/>
                        <SU>14</SU>
                         The final provisions specify which owner or operator is responsible for current and future reporting years' reports following a change in owner or operator for specific industry segments in subpart W, beginning with RY2025 reports. As described in more detail in this section, the provisions vary based upon whether the selling owner or operator will retain any emission sources, the number of purchasing owner(s) or operator(s), and whether the purchasing owner(s) or operator(s) already report to the GHGRP in the same industry segment and basin or state (as applicable). These final revisions are expected to improve data quality as described in section II.C of this preamble by ensuring that the EPA receives a more complete data set, and they are also expected to improve understanding of the rule, as described in section II.D. of this preamble.
                    </P>
                    <FTNT>
                        <P>
                            <SU>14</SU>
                             Specifically the Onshore Petroleum and Natural Gas Production, Natural Gas Distribution, Onshore Petroleum and Natural Gas Gathering and Boosting, and Onshore Natural Gas Transmission Pipeline industry segments.
                        </P>
                    </FTNT>
                    <P>In this final rule, the EPA is not taking final action at this time on the proposed amendments related to responsibility for revisions to annual reports for reporting years prior to owner or operator changes for specific industry segments in subpart W. In consideration of the relationship between revisions to annual reports for prior years and proposed implementation requirements in the 2024 WEC Proposal, the EPA intends to consider those proposed revisions in coordination with the 2024 WEC rulemaking and take action, if finalized, on these requirements at the same time.</P>
                    <P>
                        As discussed in the 2023 Subpart W proposal, we expect that transactions fall into one of four general categories, and we are finalizing provisions that specify the current and future reporting years' responsibilities for reporting for each of those general categories. First, to address transactions where an entire facility is sold to a single purchaser and the purchasing owner or operator does not already report to the GHGRP in that industry segment (and basin or state, as applicable), we are finalizing as proposed that the facility's certificate of representation must be updated within 90 days of the transaction to reflect the new owner or operator. We are finalizing as proposed the requirement that the purchasing owner or operator will be responsible for submitting the facility's annual report for the entire reporting year in which the acquisition occurred (
                        <E T="03">i.e.,</E>
                         the owner or operator as of December 31 will be responsible for the report for that entire reporting year) and each reporting year thereafter. In addition, because the definitions of facility for each of these segments encompass all of the emission sources in a particular geographic area (
                        <E T="03">i.e.,</E>
                         basin, state, or nation), the purchasing owner or operator must include any other applicable emission sources already owned by that purchasing owner or operator in the same geographic area as part of the purchased facility beginning with the reporting year in which the acquisition occurred. We proposed, but are not taking final action at this time on, a requirement that the purchasing owner or operator would also become responsible for responding to EPA questions and making any necessary revisions to annual GHG reports for reporting years prior to the reporting year in which the acquisition occurred. As noted above, we intend to consider those proposed revisions in coordination with the 2024 WEC rulemaking and take action on these requirements, if finalized, at the same time.
                    </P>
                    <P>
                        Second, to address transactions where the entire facility is sold to a single purchaser and the purchasing owner or operator already reports to the GHGRP in that industry segment (and basin or state, as applicable), we are finalizing as proposed that the purchasing owner or operator will merge the acquired facility with their existing facility for purposes of reporting under the GHGRP. In other words, the acquired emission sources will become part of the purchaser's existing facility under the GHGRP and emissions for the combined facility will 
                        <PRTPAGE P="42075"/>
                        be reported under the e-GGRT identifier for the purchaser's existing facility. We are finalizing as proposed a requirement that the purchaser will then follow the provisions of 40 CFR 98.2(i)(6) to notify the EPA that the purchased facility has merged with their existing facility and will provide the e-GGRT identifier for the merged, or reconstituted, facility. Finally, the purchaser will be responsible for submitting the merged facility's annual report for the entire reporting year in which the acquisition occurred (
                        <E T="03">i.e.,</E>
                         the owner or operator as of December 31 will be responsible for the report for that entire reporting year) and each reporting year thereafter. We proposed, but are not taking final action at this time on, a requirement that the purchasing owner or operator would also become responsible for responding to EPA questions and making any necessary revisions to annual GHG reports for the purchased facility for reporting years prior to the reporting year in which the acquisition occurred. Similarly, we are not taking final action at this time on a requirement that the acquired facility's certificate of representation be updated within 90 days of the transaction to reflect the new owner or operator. As noted above, we intend to consider those proposed revisions in coordination with the 2024 WEC rulemaking and take action on these requirements, if finalized, at the same time.
                    </P>
                    <P>Third, to address transactions where the selling owner or operator retains some of the emission sources and sells the other emission sources of the seller's facility to one or more purchasing owners or operators, we are finalizing as proposed that the selling owner or operator will continue to report under subpart W for the retained emission sources unless and until that facility meets one of the criteria in 40 CFR 98.2(i) and complies with those provisions. Each purchasing owner or operator that does not already report to the GHGRP in that industry segment (and basin or state, as applicable) will begin reporting as a new facility for the entire reporting year beginning with the reporting year in which the acquisition occurred. The new facility will include the acquired applicable emission sources as well as any previously owned applicable emission sources. We note that, under the provisions that are being finalized as proposed, because the new facility will contain acquired emission sources that were part of a facility that was subject to the requirements of part 98 and already reporting to the GHGRP, the purchasing owner or operator will follow the provisions of 40 CFR 98.2(i) and continue to report unless and until one of the criteria in 40 CFR 98.2(i) are met, instead of comparing the facility's emissions to the reporting threshold in 40 CFR 98.231(a) to determine if they should begin reporting. Each purchasing owner or operator that already reports to the GHGRP in that industry segment (and basin or state, as applicable) will add the acquired applicable emission sources to their existing facility for purposes of reporting under subpart W and will be responsible for submitting the annual report for their entire facility, including the acquired emission sources, for the entire reporting year beginning with the reporting year in which the acquisition occurred.</P>
                    <P>Fourth, to address transactions where the selling owner or operator does not retain any of the emission sources and sells all of the facility's emission sources to more than one purchasing owner or operator, we are finalizing as proposed that the selling owner or operator for the existing facility will notify the EPA within 90 days of the transaction that all of the facility's emission sources were acquired by multiple purchasers. After consideration of comment, we are revising from proposal use of the term “current owner or operator” to instead read “prior owner or operator” in the final amendments. The purchasing owners or operators will begin submitting annual reports for the acquired emission sources for the reporting year in which the acquisition occurred following the same provisions as in the third scenario. In other words, each owner or operator will either begin reporting their acquired applicable emission sources as a new facility or add the acquired applicable emission sources to their existing facility.</P>
                    <P>Finally, for the third and fourth types of transactions, we proposed but are not taking final action at this time on a set of provisions to clarify responsibility for annual GHG reports for reporting years prior to the reporting year in which the acquisition occurred. As noted above, we intend to consider those proposed revisions in coordination with the 2024 WEC rulemaking and take action on these requirements, if finalized, at the same time.</P>
                    <P>We proposed that as part of the third and fourth types of ownership change described previously in this section, the selling owner or operator and each purchasing owner or operator would be required to select by an agreement binding on the owners and operators (following the procedures specified in 40 CFR 98.4(b)) a “historic reporting representative” that would be responsible for revisions to annual GHG reports for previous reporting years within 90 days of the transaction. The proposed historic reporting representative for each facility would respond to any EPA questions regarding GHG reports for previous reporting years and would submit corrected versions of GHG reports for previous reporting years as needed. As noted above, we are not taking final action at this time on the proposed provisions for past reporting years after a transaction, including the proposed historic reporting representative provisions, and intend to consider those proposed revisions in coordination with the 2024 WEC rulemaking and take action on these requirements, if finalized, at the same time.</P>
                    <P>
                        We are finalizing as proposed amendments to 40 CFR 98.2(i)(3), the current provision that allows an owner or operator to discontinue reporting to the GHGRP when all applicable processes and operations cease to operate. Through correspondence with reporters via e-GGRT, we are aware that there have been times that an owner or operator divested a facility and was therefore no longer required to report the emissions from that facility, but even though the facility changed owners and did not cease operating, the selling owner or operator chose the provisions of existing 40 CFR 98.2(i)(3) as the reason they were ceasing to report because none of the other options fit the situation. The EPA's intent is that this reason for no longer reporting to the GHGRP should only be used in cases in which all the applicable sources permanently ceased operation. Therefore, we are finalizing as proposed amendments to clarify that 40 CFR 98.2(i)(3) will not apply when there is a change in the owner or operator for facilities in these four industry segments, unless the changes result in permanent cessation of all applicable processes and operations. We are finalizing a new paragraph at 40 CFR 98.2(i)(7) to specify that a selling owner or operator that completes the fourth transaction type discussed above (
                        <E T="03">i.e.,</E>
                         all the emission sources from the reporting facility are sold to multiple owners or operators within the same reporting year) may discontinue reporting for the facility for the reporting years following the year in which the transactions occurred provided that notification is provided to the Administrator. Prior to the addition of this new paragraph, there was not a reason provided in the regulations to discontinue reporting under 40 CFR 98.2(i) that applied to this situation.
                        <PRTPAGE P="42076"/>
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to ownership transfers.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Multiple commenters suggested that the EPA amend the reporting and ownership transfer provisions such that owners and operators would only be responsible for reporting emissions that occurred during their period of ownership or operation and that new owners should not be responsible for methane taxes generated by the prior owner. Commenters identified the WEC as a reason to reconsider reporting responsibilities. Under the structure suggested by commenters, in the case of transfer of a facility during a reporting year there would be a separate report submitted by each owner or operator. One commenter asserted that multiple reports from multiple reporters would be necessary to ensure accurate reporting as required by CAA section 136(h). The commenter further stated the proposed requirements for consolidated reporting by one owner would constitute a deviation from the IRA and increase the possibility of inaccurate reporting. Commenters further stated that new owners or operators should not be responsible for revisions to reports prior to their effective date of acquisition.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA is not taking action in this final rule on the existing subpart W requirement that the owner or operator of a facility as of December 31 is responsible for submitting a report including the entire calendar year's emissions by March 31 of the following calendar year.
                    </P>
                    <P>The EPA disagrees with the assertion that multiple reports and reporters will be necessary to ensure accurate emissions reporting. The amendments affecting ownership transfers do not impact the existing requirement that the owner or operator of a facility as of December 31 is responsible for submitting a report by March 31 of the following calendar year. The commenter did not identify specific issues with this current structure leading to the inaccurate reporting of emissions data. Rather than ensure accurate reporting as the commenter claimed, the EPA believes that preparation and submission of multiple reports by different entities related to the same emission sources would lead to duplicative burden and raise the potential for inconsistencies in reported data. The EPA therefore believes it would be neither practical nor supportive of the CAA section 136(h) directive to ensure the accuracy of reported data for the reporting responsibility for a single facility to be duplicated in multiple reports among multiple owners and operators. For these same reasons, the EPA disagrees with commenters that this implementation deviates from the IRA.</P>
                    <P>With respect to the assertion that the existing reporting structure makes the new owner or operator responsible for the methane taxes generated by the prior owner, the EPA notes that the comment concerns the timing of ownership changes and the impact upon WEC obligations and that the EPA considers these to be outside the scope of this subpart W rulemaking and they are addressed in the 2024 WEC Proposal. With respect to the assertion that retaining this reporting structure would constitute “deviating from the IRA,” the EPA notes that full calendar year reporting under subpart W was required for the facility as of December 31 at the time of signature of the IRA. The EPA finds no indication in the text of CAA section 136 suggesting that revision to this structure was mandated or intended.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Multiple commenters opposed the proposed implementation of a historic reporting representative. Some commenters suggested that a historic reporting representative was unnecessary as owners and operators should only be responsible for emissions that occurred during their time of ownership or operation, although one commenter stated that the historic reporting representative was preferable to placing the responsibility for historic reporting on the new owner or operator. Some commenters stated that there is no certainty that a historic reporting representative would have access to the data and information needed to accurately respond to questions regarding prior year reports. One commenter suggested that in place of a historic reporting representative, the EPA implement a data freeze after one year from the original submittal date of a report.
                    </P>
                    <P>One commenter supported the proposed use of a contractually determined reporting representative but asserted that some transactions may be too complicated to fit within the four categories of transactions that were proposed.</P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA is not finalizing the proposed requirements related to designation of a historic reporting representation at this time. To better facilitate implementation of the WEC under CAA section 136(c) and alignment with the final WEC rule, the EPA intends to finalize requirements related to the responsibility for historic reporting as part of a future rulemaking.
                    </P>
                    <P>The EPA acknowledges that commenters expressed concern regarding whether the individual responsible for historic reporting would have access to data and information needed to accurately respond to questions regarding GHG reporting, including potentially confidential or sensitive information and correspondence. Similarly, in past correspondence regarding the GHGRP, facility representatives have expressed concern that providing an individual access to the data and information needed for historic reporting would also provide that individual access to potentially confidential or sensitive information and correspondence submitted to e-GGRT in future year reporting. The EPA notes that the EPA is considering updating e-GGRT to implement these proposed provisions if finalized in a future rulemaking. For example, one potential update could be that the individual that an owner or operator selects to be responsible for historic reporting would be provided access to a facility's reports and correspondence limited to the reporting years for which that owner or operator was responsible for reporting for the facility. This potential implementation would prevent the individual responsible for historic reporting from accessing potentially confidential or sensitive information and correspondence for reporting years following an ownership transaction.</P>
                    <P>
                        The EPA is not implementing a data freeze for subpart W reporting as part of this final rulemaking. The EPA recognizes that resubmissions for historic reporting years have the potential to be complex due to changes in facility owners or operators, and further, that because assessment of the WEC is based upon subpart W reporting these revisions may carry financial obligations under the WEC program (compared to the GHGRP). In recognition of this potential complexity, in the 2024 WEC Proposal a deadline of November 1 was proposed for resubmission of WEC filings that would otherwise be required due to resubmission of a report under subpart W. While not at issue in this subpart W rulemaking, we note that as part of the 2024 WEC Proposal, we proposed that the EPA would retain the right to reevaluate WEC obligations in WEC filings after November 1 (
                        <E T="03">e.g.,</E>
                         as part of an EPA audit of facility data). Similarly, the proposed November 1 deadline would not apply to adjustments to WEC obligations resulting from the process to 
                        <PRTPAGE P="42077"/>
                        resolve unverified data, proposed at 40 CFR 99.8, should that resolution occur after November 1. The EPA's proposed approaches for WEC filing requirements and data verification are intended to incentivize complete and accurate WEC filings under part 99, and thus corresponding reporting of complete and accurate data under part 98 to the extent it is relevant for purposes of WEC, by March 31 of each year. The EPA anticipates that there may be situations requiring resubmissions of subpart W reports after the proposed November 1 deadline for purposes of the GHGRP, but notes that these situations would not necessarily require resubmissions or trigger a change in WEC obligation under the proposed WEC rule. The EPA is not taking final action on the requested implementation of a data freeze for subpart W reporting under this final rule and considers the comment insofar as it relates to WEC timeframes under the proposed 40 CFR part 99 to be outside the scope of this subpart W rulemaking.
                    </P>
                    <P>The EPA acknowledges the existence of complex asset transfers within the oil and gas industry but is not aware of, and the commenter did not provide an example of, a transfer that would not fit within the four categories proposed. The four categories have been finalized as proposed.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Multiple commenters stated that a new owner or operator should not be responsible for correcting or resubmitting reporters that were submitted and certified prior to their acquisition of a facility.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA is not taking final action on the proposed requirements related to designation of a historic reporting representation at this time. To better facilitate implementation of the WEC under CAA section 136(c) and align with the final WEC rule, the EPA intends to finalize requirements related to the responsibility for historic reporting as part of a future rulemaking.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter noted that in the proposed 40 CFR 98.4(n)(1) and (2) it is not directly stated which party is responsible for filing the certificate of representation following the transfer of a facility. The commenter suggested clarifying amendment to specify this is the responsibility of the new owner or operator. Another commenter stated it is unclear what is meant by the term certificate of representation.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA is finalizing 40 CFR 98.4(n)(1) and (2) as proposed. The language referenced by the commenter is consistent with the existing language at 40 CFR 98.4(h) related to updates to the certificate of representation following a change in owner or operator in the general case (
                        <E T="03">i.e.,</E>
                         for all facilities other than those specified in the final introductory paragraph at 40 CFR 98.4) and is consistent with the EPA's interpretation of that language (that such updates are the responsibility of the new owner or operator). As previously noted, the EPA plans to finalize amendments to historic reporting responsibilities in a future rulemaking. The EPA intends to consider any associated amendments related to the responsibility for updates to the certificate of representation at such time. Regarding the last comment, we note that the contents of a complete certificate of representation are listed at 40 CFR 98.4(i), which is not being amended as part of this rulemaking.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Multiple commenters addressed the impact of the proposed amendments on reporting and notification requirements for partial facility sales. One commenter opposed the proposed language at 40 CFR 98.4(n)(3) that would require both the existing and purchasing owner and operator to report for their respective emission sources until the criteria in 40 CFR 98.2(i) are met. The commenter requested that the EPA instead finalize a provision allowing the existing and purchasing owners and operators to compare their respective facility emissions to the reporting threshold in 40 CFR 98.231(a).
                    </P>
                    <P>One commenter expressed general support for the proposed revisions but stated that the proposed language for reporting requirements under the scenarios addressed at 40 CFR 98.4(n)(3) and (4) are ambiguous. The commenter recommended that the EPA clarify that in scenarios of partial facility sales the criteria of 40 CFR 98.2(i) would apply. The commenter further recommended that the EPA finalize a requirement requiring notification when any type of transaction occurs.</P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA is finalizing as proposed the provisions related to continued reporting obligations following the sale of a portion of a facility's emission sources. The EPA believes the language of 40 CFR 98.4(n)(3) is clear regarding continued reporting obligations for both the existing and the purchasing owner or operator involved in a transaction. 40 CFR 98.4(n)(3) requires that the existing owner or operator continue to report for their retained emission sources unless and until the criteria of 40 CFR 98.2(i) are met. Similarly, 40 CFR 98.4(n)(3)(i) requires that a purchasing owner or operator that does not already have a reporting facility in the same industry segment continue to report for the new facility until one of the criteria in 40 CFR 98.2(i) are met. For a purchasing owner or operator that already has a reporting facility in the same industry segment, 40 CFR 98.4(n)(3)(ii) directs that the acquired emission sources must be included in their annual report. The EPA disagrees that the reporting threshold in 40 CFR 98.231(a) should be used in place of the provisions of 40 CFR 98.2(i) to determine continued reporting obligations. The commenter that expressed general support for the provisions stated that 40 CFR 98.2(i) contemplates continued reporting for operators whose facilities no longer meet the original definition of a applicable facility under subpart A—including after they have sold assets. The final amendments ensure that the applicable requirements to cease reporting for facilities involved in the transactions to which 40 CFR 98.4(n)(3) applies are the same as the applicable requirements to cease reporting for existing facilities.
                    </P>
                    <P>The EPA did not propose, and is not finalizing, a requirement that notification is provided when any type of transaction occurs. As discussed above, the EPA believes this final rule establishes clear requirements regarding continued reporting for transferred assets. Further, the disaggregated reporting provisions finalized for the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments are expected to provide the EPA the ability to track the movement of assets without requiring specific notification of each asset transfer.</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter stated that the use of the word “current” in the proposed language of 40 CFR 98.4(n)(4) was ambiguous in the context of a transfer of ownership or operation and recommended that the EPA clarify that the new owner or operator should be required to notify the EPA of the acquisition of emission sources.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA acknowledges the potential for confusion with the term “current owner or operator” in the proposed 40 CFR 98.4(n)(4) and has instead finalized the term “prior owner or operator” in this context. The EPA has not adopted the commenter's suggestion that this requirement should instead be the responsibility of the new owner or operator. The intent of this notification is to inform the EPA that reporting will discontinue for the prior facility due to the sale of all emission sources to multiple purchasers. The EPA does not believe any single purchaser will necessarily know that all of the assets from the prior facility had 
                        <PRTPAGE P="42078"/>
                        been sold or the identity of other purchasers.
                    </P>
                    <HD SOURCE="HD3">2. Definition of “Owner” and “Operator”</HD>
                    <P>Consistent with section II.D. of this preamble, the EPA is finalizing the proposal to amend 40 CFR 98.1(c) to clarify that the terms “owner” and “operator” used in subpart A have the same meaning as the terms “gathering and boosting system owner or operator” and “onshore natural gas transmission pipeline owner or operator” for the Onshore Petroleum and Natural Gas Gathering and Boosting and Onshore Natural Gas Transmission Pipeline industry segments of subpart W, respectively. The EPA received only supportive comments on this clarification.</P>
                    <HD SOURCE="HD3">3. Onshore Natural Gas Processing Industry Segment Definition</HD>
                    <P>
                        The EPA is finalizing several amendments to 40 CFR 98.230(a)(3) as described in this section. The EPA received only minor comments on the proposed requirements related to the definition of “onshore natural gas processing” in 40 CFR 98.230(a)(3). See the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
                    </P>
                    <P>According to existing 40 CFR 98.230(a)(3), the Onshore Natural Gas Processing industry segment currently includes all facilities that fractionate NGLs. The industry segment also includes all facilities that separate NGLs from natural gas or remove sulfur and carbon dioxide (CO2) from natural gas, provided the annual average throughput at the facility is 25 MMscf per day or greater. The industry segment also currently includes all residue gas compression equipment owned or operated by natural gas processing facilities that is not located within the facility boundaries.</P>
                    <P>The EPA is finalizing as proposed an amendment to revise the definition of “onshore natural gas processing” in 40 CFR 98.230(a)(3) to specify that it includes forced extraction of natural gas liquids (NGLs) from field gas, fractionation of mixed NGLs to natural gas products, or both, similar to the definition of “natural gas processing plant” in NSPS OOOOa. The revised definition for natural gas processing also does not include the 25 MMscf per day threshold for facilities that separate NGLs from natural gas using forced extraction but do not fractionate NGLs. We are also finalizing the revisions to the term “forced extraction of natural gas liquids” in 40 CFR 98.238 as proposed to specify that forced extraction does not include “a Joule-Thomson valve, a dewpoint depression valve, or an isolated or standalone Joule-Thomson skid.” These amendments will improve the verification and transparency of the data, particularly across reporting years, consistent with section II.C. of this preamble, and it will provide reporters with certainty about the applicable industry segment for the reporting year, consistent with section II.D. of this preamble, allowing them to focus their efforts on collecting accurate monitoring data and emissions information needed for one applicable industry segment. As explained in the 2023 Subpart W Proposal, while we expect that the final revisions will result in some processing plants that have been reporting as part of onshore petroleum and natural gas gathering and boosting facilities to begin report as onshore natural gas processing facilities, and some onshore natural gas processing facilities beginning to report as part of onshore petroleum and natural gas gathering and boosting facilities, we do not expect that the overall coverage of the GHGRP will decrease.</P>
                    <HD SOURCE="HD3">4. Applicability of Proposed Subpart B to Subpart W Facilities</HD>
                    <P>
                        The EPA is not taking final action on the proposed addition of 40 CFR 98.232(n), which would have referred to subpart B of part 98 (Energy Consumption) that was proposed in the May 22, 2023, GHGRP supplemental proposed rule (88 FR 32852). For the reasons explained in section III.B. of the preamble to the GHGRP amendments that were signed by the EPA Administrator on April 3, 2024,
                        <FTREF/>
                        <SU>15</SU>
                         the EPA did not take final action on the proposed addition of subpart B of part 98. Therefore, we are not taking final action on proposed amendments to subpart W to clarify the intent for subpart W reporters to also report under subpart B. See the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for a complete listing of all comments and responses related to subpart B.
                    </P>
                    <FTNT>
                        <P>
                            <SU>15</SU>
                            A copy of the final preamble and rule is available at 
                            <E T="03">https://www.epa.gov/ghgreporting/rulemaking-notices-ghg-reporting.</E>
                        </P>
                    </FTNT>
                    <HD SOURCE="HD2">B. Other Large Release Events</HD>
                    <HD SOURCE="HD3">1. Summary of Final Amendments</HD>
                    <P>We are finalizing the inclusion of an additional emissions source, referred to as “other large release events,” to capture maintenance or abnormal emission events that are not fully accounted for using existing methods in subpart W, consistent with section II.A. of this preamble. We proposed to include calculation and reporting requirements for other large release events in the 2022 Proposed Rule and in the 2023 Subpart W Proposal. We are finalizing the definition of other large release event to include planned releases, such as those associated with maintenance activities, for which there are not emission calculation procedures in subpart W as proposed in the 2023 Subpart W Proposal, except that we are specifically excluding blowdowns for which emissions are calculated according to the provisions in 40 CFR 98.233(i) from the definition of other large release events, for reasons described later in this section. We are also finalizing the language in 40 CFR 98.233(y)(1)(ii), with modifications from proposal for clarity, that instructs the reporter to exclude emissions that would have been calculated for the source(s) of the other large release event during the timespan of the other large release event from source-specific emissions calculated under paragraphs 40 CFR 98.233(a) through (h), (j) through (s), (w), (x), (dd), or (ee), as applicable, to avoid double counting.</P>
                    <P>
                        One primary difference in the requirements we are finalizing for other large release events and those in the 2023 Subpart W Proposal is we are limiting the threshold for other large release events to include only events under this source category with an instantaneous CH
                        <E T="52">4</E>
                         emission rate of 100 kg/hr or higher or events with instantaneous CH
                        <E T="52">4</E>
                         emission rates of 100 kg/hr greater than the emissions estimated using other subpart W methods (the latter of which is applicable for events associated with calculation methods elsewhere in subpart W), which aligns with the threshold for events under the Super-Emitter Program in NSPS OOOOb and EG OOOOc, rather than having both an aggregate 250 mtCO
                        <E T="52">2</E>
                        e threshold and a 100 kg/hr methane instantaneous threshold with reporting required if either threshold was exceeded. We are also finalizing an additional clarifying sentence at 40 CFR 98.233(y)(1) to clearly state that emissions for the entire 
                        <PRTPAGE P="42079"/>
                        duration of the event must be reported as an other large release event, not just those time periods of the event in which emissions exceed the 100 kg/hr instantaneous rate threshold to ensure that the total emissions for the duration of the event are appropriately accounted for in subpart W. This clarification to the proposed provision was added to ensure that the emissions from the entire event are reported; on further review the EPA wants to ensure the requirement to calculate and report emissions from the event could not be misinterpreted, given the use of the 100 kg/hr instantaneous threshold in the final rule, as applying to only those periods when the emissions rate exceeded the 100 kg/hr emission rate threshold. Under the final provisions, we are also clarifying that events that meet or exceed the 100 kg/hr emission rate threshold when simultaneous emissions from multiple release points that have a common root cause are aggregated must be reported as a single other large release event. This approach aligns subpart W's other large release event provisions with the Super-Emitter Program, which uses remote sensing technologies that typically detect and measure the cumulative emissions from the site or facility. Even when more geospatially accurate methods are used, the measurements may still reflect the cumulative emissions from an aggregate plume created by several nearby sources within the site or facility.
                    </P>
                    <P>
                        We are not finalizing the proposed separately applicable 250 mtCO
                        <E T="52">2</E>
                        e per event threshold. After consideration of comments and further consideration of available scientific literature, we determined that the single threshold is more straightforward to implement and more consistent with the emission events we sought to include than the 250 mtCO
                        <E T="52">2</E>
                        e threshold, which could include emission events with relatively small emission rates that occur for prolonged periods of time. Our literature review reveals that tanks, unlit flares, and reciprocating compressors have been the majority of emission sources with emissions that may exceed 250 mtCO
                        <E T="52">2</E>
                        e over the duration of the emissions event but are generally below 100 kg/hr. We already have calculation methods appropriate for these sources so the vast majority of these lower rate emission events would continue to be reported under the source-specific methods and would not be reported as an other large release event, even if the 250 mtCO
                        <E T="52">2</E>
                        e threshold was retained. Thus, removing the 250 mtCO
                        <E T="52">2</E>
                        e threshold should not meaningfully reduce the emissions that would have to be reported under the other large release event provisions.
                    </P>
                    <P>Additionally, we are changing the requirements related to assessing incremental emission differences from the source-specific methodologies for blowdowns from what was proposed. Specifically, we are excluding blowdowns from the list of subpart W sources for which facilities must assess whether the incremental emissions threshold for an other large release event has been met or exceeded. Blowdowns can often have high, but short-lived, release rates that might otherwise be identified as other large release events; however, we are excluding such events from the other large release event source because our assessment is that the calculation methods for blowdown events under 40 CFR 98.233(i) are more accurate for this emission source, which has highly transient emissions. Specifically, the calculation methodology for blowdown vent stacks under 40 CFR 98.233(i) determines the total volume of between closed isolation valves and uses the pressure of the system at the start and end of the blowdown to calculate the amount of gas released, which we consider to be accurate even for large events. During a blowdown event, the emission rate will be highest at the start of the event (highest pressure) and consistently decline during the blowdown. Many remote measurements only determine the emission rate during a minute or two of observations, so projecting this instantaneous emission rate to estimate event emissions for blowdowns can be highly inaccurate. For these reasons, blowdowns will continue to be reported under blowdown vent stacks and not under other large release events, even for large emission rate events. We note that accidental ruptures of transmission pipelines at onshore natural gas transmission pipeline facilities and gathering pipelines at onshore petroleum and natural gas gathering and boosting facilities are not considered blowdowns if the isolation valves are not closed at the time of the incident because the volume of the gas released is not limited to the volume between the isolation valves that are subsequently closed to isolate the leak for repair. Considering the high pressures at which transmission pipelines operate, we expect these incidents are likely to have emissions exceeding 100 kg/hr and are most accurately assessed under the other large release event provisions.</P>
                    <P>
                        Consistent with the 2023 Subpart W Proposal, for other large release events, we are finalizing calculation requirements that rely on measurement data, if available, or a combination of engineering estimates, process knowledge, and best available data, when measurement data are not available. The final calculation procedure consists of estimating the amount of gas released and the composition of the released gas. The amount of gas released would generally be calculated based on a measured or estimated emission rate(s) and an event duration. We are finalizing provisions as proposed that the start time of the duration must be determined based on monitored process parameters, when available, such as pressure or temperature, for which sudden changes in the monitored parameter signals the start of the event. If the monitored process parameters cannot identify the start of the event, we are finalizing the requirement that reporters must assume the release started on the date of the most recent monitoring or measurement survey, including advanced technology surveys or voluntary surveys, that confirms the source was not emitting at the rates above the other large release event reporting threshold or assume a start date of 91 days prior to the date of identification, whichever start date is the most recent. We are also finalizing provisions that for the purpose of estimating the total volume of the release during the event, monitoring or measurement survey includes any monitoring or measurement method in 40 CFR 98.234(a) through (d) as well as advanced screening methods such as monitoring systems mounted on vehicles, drones, helicopters, airplanes, or satellites capable of identifying CH
                        <E T="52">4</E>
                         emissions at 100 kg/hr, with a modification from proposal to add language specifying the screening method must be capable of identifying events at this threshold at a 90 percent probability of detection as demonstrated by controlled release tests. This revision in the final provision will ensure that appropriate advanced screening methods are used. We recognize that some release events may be identified using audio, visual, and olfactory (AVO) inspections. Therefore, we are finalizing additional provisions that specify that, when an event is identified using AVO methods, previous AVO inspections are considered monitoring surveys and can be used to limit the start date of an event.
                    </P>
                    <P>
                        One change from proposal in this final rule is to the default assumptions associated with the start date of an other large release event. If no monitoring data or measurement survey data are available, we are finalizing that reporters must assume that the event 
                        <PRTPAGE P="42080"/>
                        start date occurred 91 days (three months) prior to the event identification date. We proposed a 182-day default maximum duration and requested comment on a 91-day default duration. The available data suggest that the duration of emission events exceeding 100 kg/hr is highly variable, commonly lasting several hours to several weeks but occasionally lasting 182 days or longer, as noted by one commenter.
                        <FTREF/>
                        <SU>16</SU>
                         After reviewing the available information, we determined that a 91-day default more accurately reflects an average duration than the proposed 182-day default. We note that, consistent with the directives in CAA section 136(h), we provide default durations for other sources in the GHGRP, such as equipment leaks, where leaks identified are assumed to leak all year long (when annual surveys are conducted) or since the previous survey (with the option for reporters to conduct additional surveys). For other large release events, we similarly include several provisions that allow reporters to determine the start date based on their facility's specific data, including consideration of other monitoring conducted by the facility; however, we maintain that, in the absence of other facility-specific information, a default value is needed and that default should be appropriate based on available data of other large release events at this time so as to result in reasonably accurate reporting of total emissions for the facility, as discussed in the preamble of the 2023 Subpart W Proposal and in the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule,</E>
                         available in the docket to this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234). Based on consideration of the comments received and for reasons discussed in section III.B.2. of this preamble, we are finalizing the default start date of the event, when other information is not available to support a shorter duration, would be 91 days from the time the event was first identified. We are aware that many events may be shorter than 91 days; under the final provisions operators may choose to gather and use other specified information to determine the actual duration, to avoid the potential need to apply a default start date for such events. As new data on event duration becomes available, we intend to evaluate if the default event should be updated in the future through a future rulemaking process. We are revising from proposal the language regarding this 91-day default start date to more clearly specify that it is used to establish the start date of the event. The 91-day default start date prior to the date of detection does not limit the cumulative duration of an event in cases where the repair or cessation of the emissions is delayed after the date of event detection. For example, if an event is immediately identified but takes 120 days to repair, the full duration of the event (120 days) must be used. The 91-day default only applies to the determination of the start date and not the cumulative duration. We are finalizing, as proposed, that the end time of the release event must be the date of the confirmed repair or confirmed cessation of emissions. There may be events that span across two separate reporting years. In such cases, we are finalizing as proposed that the volume of gas released specific to each reporting year would be calculated and reported for that reporting year starting with RY2025.
                    </P>
                    <FTNT>
                        <P>
                            <SU>16</SU>
                             Kairos Aerospace comments on the Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems. Letter from Ryan Streams, Kairos Aerospace, to Jennifer Bohman and Mark DeFigueiredo, U.S. EPA, September 29, 2023. EPA Docket Id No. EPA-HQ-OAR-2023-0234-0240. “However, Kairos has also noted instances where emissions that would qualify as “Other Large Release Events” do appear to be highly persistent in nature. Kairos analyzed our emission detections during 2022 across the Anadarko, Barnett, DJ, Eagle Ford, Haynesville, Permian, San Joaquin, San Juan, and Uinta Basins and observed 714 upstream sites that had emissions that persisted for at least 182 days. This does not represent a majority of Kairos detections—Kairos observes thousands of emissions per year, the majority of which persist for less than 182 days—but it does appear that long duration events can happen.”
                        </P>
                    </FTNT>
                    <P>For explosions or fires where some of the gas may be combusted or partially combusted, we are finalizing that reporters must estimate the portion of the total volume of natural gas released that was combusted in the explosion or fire in order to determine the composition of GHG released to the atmosphere during the event. For the portion of natural gas released via combustion in an explosion or fire, we are finalizing as proposed that a maximum combustion efficiency of 92 percent be assumed. Because these releases are not through engineered nozzles that can be designed to promote mixing and combustion efficiency, the combustion efficiency of these releases can be highly variable and are expected to be less efficient than a flare designed to destroy methane. Since facilities must first estimate the fraction of the gas released via combustion, we expect that the total combustion efficiency, considering all gas released over the length of the event, will be much lower than 92 percent.</P>
                    <P>
                        We are finalizing requirements for facilities to evaluate releases when there is monitoring or measurement data completed by the EPA or the facility. We are also finalizing requirements for facilities to evaluate releases when there is a notification from the EPA Super-Emitter Program in NSPS OOOO/OOOOa/OOOOb at 40 CFR 60.5371, 60.5371a, 60.5371b or an applicable approved state plan or applicable Federal plan in 40 CFR part 62. After consideration of comments received, as discussed in section III.B.2. of this preamble, and in alignment with the final provisions of the Super-Emitter Program in NSPS OOOO/OOOOa/OOOOb and EG OOOOc, we are not finalizing the proposed provision that subpart W reporters must consider other third-party information (
                        <E T="03">i.e.,</E>
                         information from parties other than the EPA's or facility's sponsored monitoring events or notifications of large potential super-emitter events under the Super-Emitter Program in NSPS OOOO/OOOOa/OOOOb and EG OOOOc received by the facility from the EPA), and are accordingly not finalizing the use of the term “credible information.” Other third-party notifications are not assured of having the credibility and defined requirements that notifications from the EPA under the Super-Emitter Program, or data from monitoring or measurement conducted by the EPA or the facility, will have and the EPA has concluded that it is not appropriate to place a potentially large burden on subpart W reporters to respond to such information. The final provisions of the Super-Emitter Program in NSPS OOOO/OOOOa/OOOOb have robust assurances of credibility, reliability and transparency. The entities doing the super-emitter monitoring under NSPS OOOO/OOOOa/OOOOb must have the remote-sensing technology they are using (
                        <E T="03">e.g.,</E>
                         satellites) certified by the EPA under the EPA's advanced methane detection technology program, including rigorous accuracy checks, where the EPA is certifying that the technology used is capable of providing accurate and reliable data within the requirements of the Super-Emitter Program. The entity filing the super-emitter report must also be certified by the EPA, to demonstrate that the third party has the training and expertise to interpret the data and identify a super-emitter event and has appropriate and reliable methods for identifying the owner or operator of the sites where the super-emitter event occurred. The third-party reports must be filed with the EPA 
                        <PRTPAGE P="42081"/>
                        within 15 days of detection, increasing the opportunity for the owners and operators to get timely notice, and must also meet specified reporting criteria and be filed under attestation that the information is true and accurate to the best of the notifier's knowledge. Once the super-emitter report is received by the EPA, the EPA evaluates the report for completeness and accuracy before sending a super-emitter notice to the owner or operator. The super-emitter notices, and the owner or operator's response, will all be posted to a public website. All of these requirements and the significant oversight role the EPA assumes in certifying both the technology and the reporter, as well as the checks performed once the reports are submitted to the EPA, demonstrate that the data underlying the EPA's notices are credible and reliable and thus support the EPA's conclusion that the emissions included in the super-emitter notices from the EPA must be evaluated for a facility's subpart W report. We note that our judgment regarding the revisions to requirements for each type of source within each subpart W industry segments reflects our determinations specific to considerations for each source in each industry segment, including other large release events. More specifically here, the revisions for other large release events are intended to be and are implementable even absent revisions to the other sources, and vice versa, as they each independently ensure that the emissions reported under subpart W for the given source or industry segment at issue are consistent with the directives in CAA section 136(h) and improve the subpart W provisions as described in section II. of this preamble. Furthermore, the other large release event requirements for facilities to evaluate releases when there is monitoring or measurement data completed by the EPA or the facility are intended to be and are implementable even absent the other large release event requirements for facilities to evaluate releases when there is a notification from the EPA Super-Emitter Program in NSPS OOOO/OOOOa/OOOOb at 40 CFR 60.5371, 60.5371a, or 60.5371b or an applicable approved state plan or applicable Federal plan in 40 CFR part 62. Accordingly, the EPA finds that these other large release event requirements are severable from each other, and that at minimum revisions for each source are severable from revisions to each of the other sources.
                    </P>
                    <P>
                        Under the Super-Emitter Program, the EPA may receive third-party notifications and in turn notify owners and operators of potential super-emitter events that are related to subpart W facilities, including subpart W facilities that either do or do not have NSPS OOOO/OOOOa/OOOOb or EG OOOOc affected facilities. Under subpart W, we are finalizing that owners and operators are required to report whether emission events identified in those notifications are included in their annual emissions report and if so, under which source category. We are clarifying in the final rule that facilities must include in the facility's annual emissions report emissions events identified in super-emitter notices received from the EPA unless the owners and operators can certify that the facility does not own or operate the equipment at the location identified in the notification or, in situations where there are multiple facilities that own and operate equipment within 50 meters of the location identified in the notification, the owners and operators can certify that their facility does not own or operate the emitting equipment at the location identified in the notification or unless the EPA has determined that the notification contains a demonstrable error. For consideration of demonstrable error, the facility must submit a statement of demonstrable error as specified by 40 CFR 60.5371, 60.5371a, or 60.5371b or an applicable approved state plan or applicable Federal plan in 40 CFR part 62.
                        <FTREF/>
                        <SU>17</SU>
                         We are finalizing additional requirements for actions the owners and operators must complete in order to be able to certify that the facility does not own or operate the emitting equipment at the location identified in the notification in situations where there are multiple facility owners and operators of equipment at the location. Specifically, the facility must complete an investigation of available data as specified in 40 CFR 60.5371b(d)(2)(i) through (iv) within 5 days of receiving the notification to identify the emission source related to the event. If this data investigation does not identify the emission source, the facility must conduct a complete leak survey of equipment within 50 meters of the location identified in the notification using any one of the methods provided in § 98.234(a)(1) through (3) within 15 days of receiving the notification. If the data investigation and the leak survey both fail to identify the source of the event, then the facility owner or operator can certify that they do not own the emitting equipment.
                    </P>
                    <FTNT>
                        <P>
                            <SU>17</SU>
                            Under the Super-Emitter Program, the owner or operator has 15 days to submit a report, which could include a statement of demonstrable error challenging the notification. Events occurring during a calendar year are not reported to the GHGRP until the following March. We also note that facilities have the ability to revise their annual reports after submission if errors are identified.
                        </P>
                    </FTNT>
                    <P>Further, we are finalizing as proposed definitions of the terms “well release” and “well blowout” in 40 CFR 98.238 to assist reporting facilities with differentiating between these types of release events that could potentially occur at wells.</P>
                    <P>
                        Finally, we are finalizing a series of reporting requirements in 40 CFR 98.236(y) related to the type, location, duration, calculations, and emissions of each “other large release event” similar to those proposed. Specifically, we are finalizing as proposed that reporters provide the location, a description of the release (from a specified list that includes an “other (specify)” option for releases that are not otherwise described well with the list provided), a description of the technology or method used to identify the release, volume of gas released, volume fractions of CO
                        <E T="52">2</E>
                         and CH
                        <E T="52">4</E>
                         in the gas released, and CO
                        <E T="52">2</E>
                         and CH
                        <E T="52">4</E>
                         emissions for each “other large release event.” We are also finalizing that reporters would provide the start date and time of the release, duration of the release, and the method used to determine the start date and time (options would include a pressure monitor, a temperature monitor, other monitored process parameter, most recent monitoring or measurement survey showing no large release (and specify the type of monitoring or survey), or the default assumption that the release started 91 days prior to the event identification date). As previously explained in this section, the 91 days start date would be the required assumption if the facility does not have empirical data, such as monitored process parameter data or leak inspections or advanced technology monitoring or measurement surveys, to identify the release start date, a reduction from the 180 days proposed. These provisions are otherwise being finalized as proposed except for minor revisions to reflect the revisions and clarifications pertaining to the default assumption start date. We are also finalizing as proposed that reporters provide a general description of the event and indicate whether the “other large release event” was also identified as a potential super-emitter event under the super-emitter event provisions of NSPS OOOO/OOOOa/OOOOb at 40 CFR 60.5371, 60.5371a, or 60.5371b or an applicable approved state plan or applicable Federal plan in 40 CFR part 62.
                    </P>
                    <P>
                        We are finalizing that reporters that received super-emitter event 
                        <PRTPAGE P="42082"/>
                        notifications from the EPA would be required to report certain information on each release notification with some revisions from proposal. We are adding language to limit reporting requirements for super-emitter event notifications to those for which the EPA does not determine that the notification contains a demonstratable error. For consideration of demonstrable error by the EPA, facilities must describe the demonstrable error in their Super-Emitter Program report according to the provisions of NSPS OOOO/OOOOa/OOOOb at 40 CFR 60.5371, 60.5371a, or 60.5371b or an applicable approved state plan or applicable Federal plan in 40 CFR part 62. We are finalizing that for each EPA notification received via the Super-Emitter Program (for which the EPA does not subsequently determine that the notification contains a demonstrable error), facilities would report the type of event resulting in the emissions as one of the following types of events: normal operations, a planned maintenance event, leaking equipment, malfunctioning equipment or device, or undetermined cause. Because all Super-Emitter Program notifications will come from the EPA, we are not finalizing certain proposed reporting requirements regarding the notification since the EPA will already have this information (
                        <E T="03">e.g.,</E>
                         name of notifier, method used, date of measurement, and emission rate and uncertainty bounds). We are finalizing that facilities must indicate whether the emissions identified from the event are included as an other large release event, as another source required to be reported under subpart W, or not included. The only exception to the requirement to include emissions identified via the notification in emissions reported by the facility under subpart W is if the facility is able to make a determination, and then certify to the EPA that the facility does not own or operate the equipment at the location identified in the Super-Emitter Program notification. We are not finalizing the proposed requirement that the reporter provide a reason for not including the emissions from the event in their annual emissions report, as all emission events identified under the Super-Emitter Program that are the subject of a notice from the EPA to the owner/operator must be quantified unless the exception applies and the owner or operator of the facility certifies that the exception applies. This information would support EPA verification and ensure accuracy of the emissions reported under other large release events and the facility's total reported emissions.
                    </P>
                    <P>We are not finalizing several of the proposed reporting requirements under subpart W regarding notifications under the Super-Emitter Program because all of the Super-Emitter Program notifications will be issued by the EPA and the EPA will already have records of the information we had proposed to require be submitted under subpart W. Specifically, we are not finalizing requirements proposed at 40 CFR 98.236(y)(11)(ii) to report the latitude and longitude of the release as reported in the notification. Also, we are not finalizing requirements proposed at 40 CFR 98.236(y)(11)(iv) to report whether the release was received under the super-emitter event provisions of NSPS OOOO/OOOOa/OOOOb at 40 CFR 60.5371, 60.5371a, or 60.5371b or an applicable approved state plan or applicable Federal plan in 40 CFR part 62 or another notifier, and, if the notification was from another notifier, the reporter would provide the name of the notifier, the remote sensing method used, the date and time of the measurement, the measured emission rate, and uncertainty bounds on the emission rate. These changes from proposal align with the final requirements in the Super-Emitter Program under NSPS OOOO/OOOOa/OOOOb and EG OOOOc and ensure we are not finalizing duplicative reporting requirements.</P>
                    <P>Finally, we are adding a reporting requirement to provide an indication if you received a super-emitter release notification from the EPA after December 31 of the reporting year for which investigations are on-going such that the annual report that has been submitted may be revised and resubmitted pending the outcome of the super-emitter investigation. This reporting element is provided in recognition of the fact that some super-emitter notifications received in 2026 may impact the 2025 reporting year annual report and there may not be sufficient time to revise the 2025 annual report prior to the March 31 deadline. This reporting element allows the reports to be certified as accurate for submission while noting the potential need for revision depending on the outcome of the super-emitter release notification investigation.</P>
                    <HD SOURCE="HD3">2. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to add the other large release events source category.</P>
                    <P>
                        <E T="03">Comment:</E>
                         We received numerous comments on the proposed thresholds for defining a reportable other larger release event. Several commenters supported both of the thresholds included in the 2023 Subpart W Proposal and some commenters recommended smaller reporting thresholds, specifically reducing the 100 kg/hr to 14 kg/hr. However, a majority of the comments received opposed one or both of the thresholds. Commenters opposing the 250 mtCO
                        <E T="52">2</E>
                        e threshold generally considered it to be too small, especially considering the proposed 182-day default start date. One commenter stated “. . . it would take approximately 90 days for a 4.7 kg/hr CH
                        <E T="52">4</E>
                         leak to exceed the proposed 250 mtCO
                        <E T="52">2</E>
                        e threshold. . . A `large release event' should be just that, not a small release over a long period of time.” Many of these commenters suggested that the EPA adopt the Pipeline and Hazardous Materials Safety Administration (PHMSA) threshold for a reportable incident of 3 MMscf (approximately 6 times higher that the proposed threshold).
                    </P>
                    <P>Regarding the 100 kg/hr threshold, a few commenters suggested this emission rate was too high and that a lower threshold should be adopted but most of the commenters recommended that a time component was needed with this threshold because in their view high rate, short duration events would still have small contributions to a facility's annual emissions. Many of the commenters making this argument specifically cited blowdowns as sources with high release rates and short durations and indicated that these types of events should not be considered under the other large release event provisions.</P>
                    <P>
                        Several of the commenters indicated that the EPA should use a combined threshold (exceed 250 mtCO
                        <E T="52">2</E>
                        e AND 100 kg/hr methane) rather than the two independent thresholds proposed (exceed 250 mtCO
                        <E T="52">2</E>
                        e OR 100 kg/hr methane). These commenters noted that this would address issues with low rate, long duration events being considered as other large release events as well as setting a minimum emission quantity for high release events, so short duration, high rate releases such as blowdowns would not be considered under the other large release event provisions. A few of the commenters suggesting a combined threshold also suggested increasing thresholds levels.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         After considering comments received, we are finalizing the 100 kg/hr threshold as proposed, but we are not finalizing the proposed 250 mtCO
                        <E T="52">2</E>
                        e threshold. We determined that the single threshold will be more straightforward for operators to implement, aligns more directly with 
                        <PRTPAGE P="42083"/>
                        the EPA's Super-Emitter Program, and is more consistent with the emission events we sought to include in the other large release events source than the 250 mtCO
                        <E T="52">2</E>
                        e limit. Furthermore, based on our literature review of emission sources with emissions below 100 kg/hr, tanks, unlit flares, and reciprocating compressors were the majority of these smaller rate emitters. In this final rule, we have calculation methods appropriate for these sources that accurately estimate emissions from events with emission rates less than 100 kg/hr and determined that removing the 250 mtCO
                        <E T="52">2</E>
                        e threshold would not significantly reduce the emissions that would have to be reported under the other large release event provisions because these sources would always be reported under the source-specific reporting requirements, as amended, rather than under other large release event provisions.
                    </P>
                    <P>We disagree with commenters requesting a smaller 14 kg/hr methane emission rate threshold. First, this emission rate is at or below the level of detection for several remote sensing methods. Second, this would cause a disconnect between the final other large release event threshold and the NSPS Super-Emitter Program requirements.</P>
                    <P>
                        Regarding commenters suggesting that the 100 kg/hr threshold alone is not appropriate because high rate, short events may have low cumulative emissions and commenters suggestion that the EPA implement one combined threshold exceeding both the 100 kg/hr and the 250 mtCO
                        <E T="52">2</E>
                        e limit, we disagree that these high emission rate events should not be reported when they are from sources not otherwise subject to reporting under subpart W or from sources for which the source-specific method significantly understates the emissions. We also disagree that the 250 mtCO
                        <E T="52">2</E>
                        e threshold should be applied to limit the number of releases exceeding 100 kg/hr that should be accounted for within the subpart W other large release event reporting requirements. CAA section 136(h) directed the EPA to revise subpart W to accurately reflect total methane (and waste emissions). Combining the thresholds would cause a disconnect between the Super-Emitter Program and the GHGRP reporting requirements where some NSPS OOOOb or EG OOOOc super-emitter events would not be reported under the subpart W and result in the underreporting of methane emissions to subpart W. Several of the commenters provided hypothetical calculations of mass emissions that would occur for events right at the 100 kg/hr rate for 1 to 5 minutes but offer no data to support that such events are prevalent. We also note that remote detection of high release events relies on an adequate pathlength concentration being present, which would not be the case for these hypothetical short duration events. These methods generally make flux calculations using wind speeds and/or dispersion models that typically assume a developed plume, but the plume would not be fully developed for these hypothetical short events. Even if the emission event can be detected and quantified by the monitoring technique used, it is highly unlikely that the remote monitoring measurement would occur precisely at the time of the 1- to 5-minute release. As such, we find the commenter's concern regarding the need to evaluate numerous very short events is largely unfounded. Nonetheless, we did evaluate potential release events that may be of short duration, as described in the following paragraph.
                    </P>
                    <P>When commenters provided an example of high-rate, short events, they all pointed to blowdown events. However, blowdowns have their own calculation method, which we consider to be accurate across the duration of the event. Specifically, the blowdown methodology determines the total volume of natural gas between closed isolation valves and uses the pressure of the system at the start and end of the blowdown to calculate the amount of gas released. During the blowdown event, the emission rate will be highest at the start of the event (highest pressure) and consistently decline during the blowdown. Many remote measurements only determine the emission rate during a minute or two of observations. Projecting this instantaneous emission rate to estimate event emissions for blowdowns can be highly inaccurate. Therefore, in the final provisions we have removed the proposed cross-reference to 40 CFR 98.233(i) for blowdowns in the definition of other large release events so no additional calculations are necessary for the emissions from blowdown activities. If a facility fails to close an isolation valve and an intended blowdown event is actually a continuous venting event, such an event is not a blowdown and would have to be reported as an other large release event if it exceeds the 100 kg/hr threshold.</P>
                    <P>Besides blowdowns, the other likely high rate, short duration release event is pressure relief device (PRD) openings. Currently, PRDs are included under equipment leaks to account for periods when there is a leak past the PRD valve while it is in the closed position, but pressure relief events (periods when the valve intentionally opens due to an over-pressuring of the process vessel or equipment) are not accounted for under most circumstances. For uncontrolled production storage tanks, the calculation method assumes all dissolved methane in fluids from the separator are emitted from the tank. For controlled tanks, we require facilities to assume a zero percent capture/control efficiency over the time period the thief hatch is open (which commonly works as a PRD for the storage tank). Because large, direct PRD releases are not captured elsewhere in subpart W except for storage tanks, we maintain that these emissions must remain reportable as other large release events when the applicable threshold is met to accurately reflect methane emissions from the facility. We note that CAA section 136(h) requires that the EPA revise the requirements of subpart W to accurately reflect the total methane emissions from applicable facilities.</P>
                    <P>We expect that most short duration events will be adequately captured under source-specific provisions of subpart W, as included in the final rule. Additionally, with the 100 kg/hr emission rate threshold and exclusion of blowdowns, we expect that there will be a limited number of events that qualify under the provisions of other large release events. However, we maintain that the emissions from large emission rate events that are currently not required to be reported or that are not well-characterized under other provisions of subpart W must be reported as other large release events as directed under CAA section 136(h).</P>
                    <P>
                        <E T="03">Comment:</E>
                         Numerous commenters opposed the proposed requirement that “. . . if you have credible information that demonstrates the release meets or exceeds one of the thresholds or credible information that the release may reasonably be anticipated to meet or exceed (or to have met or exceeded) one of the thresholds in paragraph (y)(1) of this section, then you must calculate the event emissions and, if the thresholds are confirmed to be exceeded, report the emissions as an other large release event.” Some commenters expressed concern that this requirement would create a disincentive to voluntary, site-wide monitoring. The commenters also stated that “credible information” is poorly defined. Additionally, commenters opposed the proposed reporting requirements that reporters must consider and report on “third-party notifications” because unqualified third-party notifications could unnecessarily increase the reporting burden while not leading to more accurate GHG reporting. The 
                        <PRTPAGE P="42084"/>
                        commenters also challenged the legality of this requirement. According to the commenters, CAA section 114 authorizes the EPA only to collect information and it does not authorize the EPA to impose a mandatory reporting obligation that would be triggered by third-party observations or assertions. The commenters also state that any third-party data should be thoroughly vetted by the EPA and should require assessment of persistence of the observed emissions rather than relying on a single observation. One commenter expressed concern that without a robust structure in place, third party notices could be received on March 30 that require revisions to annual reports due on March 31, which the commenter considered unreasonable. Other commenters stated that the EPA must define “credible evidence,” allow operators to account for telemetry malfunctions, and remove requirements for reporters to respond to third-party notifications.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We agree with commenters that the EPA should have a role in authorizing third-party measurement systems and collecting and submitting notifications that trigger a reporting obligation under subpart W. Under the Super-Emitter Program, third parties must be EPA-certified entities, who must use EPA-approved remote sensing technologies and approaches. Under the Super-Emitter Program, the EPA will play an important oversight role, including notifying owners and operators after reviewing third-party notifications of events received under the Super-Emitter Program. It is within our authority for this subpart W rule to require reporters to assess the information that we have vetted and sent to them as notifications through the Super-Emitter Program, as it is data that we will have assessed as robust as part of that program, is based on empirical data, and is relevant to accurate calculations of emissions for the facility. Owners and operators identified through the Super-Emitter Program will also investigate and report all sources that they suspect may have caused or contributed to the super-emitter event specified in the EPA notice that they have received. Regarding our authority for the NSPS Super-Emitter Program itself, that is outside the scope of this rulemaking; please see the discussion of our authority in the NSPS OOOOb final rule (see 89 FR 16876-16879, March 8, 2024).
                    </P>
                    <P>In this final rule, we are not finalizing the proposed term “credible information” and simply describing in 40 CFR 98.233(y) the types of information that must be considered. Specifically, we are requiring that facilities consider both EPA-verified notifications provided under the Super-Emitter Program in NSPS OOOOb or federal or state plans consistent with EG OOOOc and any EPA- or facility-funded monitoring data that identify high emission events. Facility owners and operators are required to assess whether those emission events meet the definition of other large release event or are adequately reported under other provisions of subpart W. Owners or operators are not required to consider any other third-party monitoring data besides those received through a notification from the EPA or funded by EPA or the facility, but may consider other third-party data at their discretion. This eliminates the concerns noted by the commenters regarding unvetted and unsolicited third-party notifications.</P>
                    <P>If a company-sponsored monitoring event (whether voluntary or regulatorily required) indicates an other large release event and site operation staff confirm the release, such emissions should be reported, particularly given the direction under CAA section 136(h). Commenters raised concerns that this may discourage facilities from conducting voluntary site-wide monitoring; however, we consider that the structure of directives Congress gave the EPA under CAA section 136(h), which the EPA acted consistent with in this final rule, provides an incentive for routine monitoring. Routine or continuous monitoring allows a facility to both reduce waste emissions and identify an accurate number and duration of other large emission events. The EPA recognizes that the option for reporters to submit additional empirical data for a given facility may lead to reporters taking additional voluntary actions for subpart W reporting, including for the purpose of demonstrating the extent to which a charge under CAA section 136(c) is owed. To the extent this approach “incentivizes” additional actions by the reporter, the EPA considers this to be inherent in the directives Congress gave the EPA in CAA section 136(h). The EPA considers this approach consistent with the directives Congress specified in CAA section 136(h), as it ensures that reporting is based on empirical data and accurately reflects total methane emissions while also allowing reporters to submit appropriate empirical emissions data. We also note that facilities must still act on EPA-provided notifications (from the Super-Emitter Program) about large release events.</P>
                    <P>With respect to concerns about notifications impacting soon to be submitted or previously submitted annual reports, we first note that the 15-day maximum timeframe for third-party notifiers to submit information to the EPA under the Super-Emitter Program will ensure facilities will be notified of super-emitter events in a timely manner. For events for which start times can be determined, which we expect to be most events, notifications received in late March are unlikely to require revisions of the annual report due at the end of March because it is likely that the facility is already aware of the event from data regularly monitored by the facility. Second, with the revised default start date being 91 days from event identification rather than 182 days, it is much less likely that notifications received at the end of March 2026, for example, would impact the emission totals for the 2025 reporting year, which ends 89 days before the report due date. However, we acknowledge that there may be circumstances that notifications are received near the March 31 due date and there would not be time to evaluate the notification prior to the reporting deadline. In this circumstance, facilities should submit their report to the best of their knowledge. We added a reporting element at 40 CFR 98.236(y)(11)(v) for reporters to provide an indication of whether they have received a super-emitter release notification after December 31 of the reporting year for which an investigation is on-going and might result in the need to revise and resubmit the annual report pending the outcome of the super-emitter investigation. If upon determining the start date and duration of the event, the some of the event's emissions are reportable for the report already submitted, facilities are able to amend the previously submitted annual report to include the applicable event emissions and resubmit that annual report. We note that facilities have 45 days under 40 CFR 98.3(h)(1) to resubmit and correct their annual report after identifying a substantive error, which would afford them additional time to evaluate the event.</P>
                    <P>
                        While persistence is not specifically included in the Super-Emitter Program notification requirements, many of the remote sensing technologies use multiple determinations (
                        <E T="03">e.g.,</E>
                         multiple transects at different heights) to meet required accuracy assessments. 
                        <E T="51">18 19</E>
                        <FTREF/>
                         For 
                        <PRTPAGE P="42085"/>
                        a super-emitter notification that the EPA determines is complete and does not contain information that the EPA finds to be inaccurate to a reasonable degree of certainty, we maintain that it is reasonable to require facilities to report these emissions, even when they may be short-lived. Because some remote measurements may identify an aggregate emission rate from the site or facility that exceeds 100 kg/hr but would not have the spatial resolution to identify the specific source or sources, reporters will need to investigate and identify the source of the emissions. We note that in certain situations, such as a process unit over-pressuring, there may be multiple release points (such as several different PRDs opening at the same time). For these types of releases, we find it reasonable to aggregate the emissions from all release points that have a common root-cause and consider that a single “event” because this would more closely tie reported emissions to the available monitoring data.
                    </P>
                    <FTNT>
                        <P>
                            <SU>18</SU>
                            Karion, A., 
                            <E T="03">et al.,</E>
                             “Aircraft-Based Estimate of Total Methane Emissions from the Barnett Shale Region.” 
                            <E T="03">Environ. Sci. Technol.</E>
                             2015, 49, 8124-8131. 
                            <E T="03">https://pubs.acs.org/doi/10.1021/acs.est.5b00217.</E>
                             Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                            <PRTPAGE/>
                        </P>
                        <P>
                            <SU>19</SU>
                            Schwietzke, S., 
                            <E T="03">et al.,</E>
                             “Improved Mechanistic Understanding of Natural Gas Methane Emissions from Spatially Resolved Aircraft Measurements.” 
                            <E T="03">Environ. Sci. Technol.</E>
                             2017, 51, 7286-7294. 
                            <E T="03">https://pubs.acs.org/doi/10.1021/acs.est.7b01810.</E>
                             Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        <E T="03">Comment:</E>
                         Several commenters supported the 182-day default duration. One commenter noted that they had observed 714 upstream sites that (1) had emissions that would qualify as an other large release event under the subpart W proposal, and (2) persisted for at least 182 days. While the majority of the site-level emission detected by the commenter persisted for less than 182 days, the commenter noted that long duration events can occur. On the other hand, numerous commenters opposed the 182-day default duration. These commenters argued that the 182-day duration would effectively require facilities to do more frequent monitoring to avoid having to use the 182-day default duration. Several of these commenters indicated that the 91-day default duration that the EPA requested comment on was more appropriate. Other commenters suggested a default duration of 30 or 45 days may be more appropriate given the typical duration of large release events. Other commenters recommended that reporters be permitted to use a wide variety of methods, including audio, visual and olfactory methods, optical gas imaging (OGI) surveys, flyovers, process parameters, and Supervisory Control and Data Acquisition (SCADA) systems, to determine the start and end time of such events. Some commenters suggested process knowledge and engineering estimates be allowed to determine event duration.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         After reviewing comments, we have decided to finalize the default start date of an event to be 91 days prior to event identification rather than the proposed 182 days. While we also inadvertently referred to this as a default duration in our 2023 Subpart W Proposal, we intended this to be the default start date (in the absence of any monitored process data, survey or remote sensing data suggesting a more recent start date). As further indication of our intent, we note that the paragraph at 40 CFR 98.233(y)(2)(ii) is specific to determining the start date of the event and a separate paragraph—40 CFR 98.233(y)(2)(iii)—provides the provision for the end time. Nonetheless, based on comments received, it appears some commenters may have interpreted this to be a maximum event duration; therefore, we are clarifying in the final provisions in 40 CFR 98.233(y)(2)(ii) that, in the absence of monitored process parameter data indicating the start date, the event must be assumed to start on the date of the most recent monitoring or measurement survey that confirms the source was not emitting at or above the rates specified in 40 CFR 98.233(y)(1) or assumed to have started 91 days prior to the date the event was first identified, whichever start date is most recent. Therefore, we are limiting how far back in time the default start date is from the date the event was first identified, but we are not limiting the maximum duration of the event. For example, the Aliso Canyon event was identified soon after it started since the natural gas contained odorant, but the leak took months to repair and had a total duration of about 112 days. In a case with these facts under the final provisions, the duration of the event must still be reported as 112 days based on the identified start date and the confirmed repair date of the leak.
                    </P>
                    <P>The literature study data we reviewed, as detailed in the subpart W TSD for the final rule (included in Docket ID. No. EPA-HQ-OAR-2023-0234), suggest that the duration of emission events exceeding 100 kg/hr is typically short and that a 91-day default more accurately reflects the typical range of observed durations expected to be reported under this source category than the proposed 182-day default. For example, well blowouts, which is a source of emissions that will be reported under other large release events, often persist for an extended period of time. We disagree with commenters that the default duration should be reduced further, for example to 30 days, because this could in many cases result in under-reporting, and will also disincentivize facilities from trying to pinpoint actual start dates for events that may have started 30 or more days prior to event detection. We also expect that most short duration events will be adequately captured under source-specific provisions of subpart W, as included in the final rule. We also note that, as discussed above, blowdowns, the often-cited example of high-rate, short events, have been excluded from the final provisions for assessment as an other large release events and are required to be reported under the provisions at 40 CFR 98.233(i) for blowdown vent stacks. We also have strong evidence that longer duration events do occur, as noted by one commenter. With the clarification that this default relates only to the start date of the event, we maintain that emissions from longer duration events will still be accurately characterized when using this 91-day default event start date because this default does not limit the total duration of the event in cases where it may take days to several months or longer to correct the issue. While we revised from proposal the default start date, we still expect that this default start date provisions will not be used often and that most facilities will be able to identify a start time based on monitored process parameter data or routine monitoring surveys.</P>
                    <P>
                        We intentionally provided flexibility for using monitored process parameters for determining the start time of a release in the proposed rule without trying to limit the types of parameters that could be monitored to identify the start date of an event. We note that data from SCADA systems are considered monitored process parameters. If a facility has a continuous monitoring network, they can also use that data to identify the start time. If a facility conducts frequent advanced technology or remote sensing surveys, these can be used to more directly assign a start date, provided that the advanced screening method is capable of identifying events with CH4 emission rates of 100 kg/hr at a 90 percent probability of detection as demonstrated by controlled release tests. We allow process knowledge and engineering estimates in the review of the process data to identify the event start date. However, we maintain that monitored parameters must be used to make these assessments. The comments received could be construed to suggest the facility should be able to pick a start date in the absence of monitored process parameters. This is inconsistent with our intent when allowing process knowledge or engineering estimates for 
                        <PRTPAGE P="42086"/>
                        other reporting elements. To ensure clarity on the use of process knowledge or engineering estimates, we are retaining the proposed language that the start time must be determined based on monitored process parameters and adding that “sound engineering principles” are to be used to determine the start time based on the monitored process parameter.
                    </P>
                    <P>We note that most of the monitoring methods suggested by commenters to identify the start date were already proposed at 40 CFR 98.233(y)(2)(iv). At proposal, we did not include AVO monitoring in the list of monitoring inspections provided in 40 CFR 98.233(y)(2)(iv) because the ability of AVO to identify a large event is highly dependent on the height, location, and characteristics of the release. However, we also recognize that on-site AVO inspections may identify some other large release events. If the event is identified via AVO methods, then we think that it logically follows that it is reasonable to allow the use of previous AVO inspections conducted for that equipment to limit the default assumed start date that would otherwise apply (if no monitoring process parameter data or other monitoring or measurement survey is available). Therefore, we are adding an additional sentence to final 40 CFR 98.233(y)(2)(iv) that states that AVO inspections are considered monitoring surveys if and only if the event was identified via an AVO inspection.</P>
                    <P>Reporters are allowed under the final rule and may prefer to undertake more frequent surveys and submit empirical emissions data because such an approach could shorten the estimated duration of the event. The EPA recognizes that the option for reporters to submit additional empirical data for a given facility may lead to reporters taking additional voluntary actions for subpart W reporting, including for the purpose of demonstrating the extent to which a charge under CAA section 136(c) is owed. As previously explained in response to comment earlier in this section, to the extent this approach “incentivizes” additional actions by the reporter, the EPA considers this to be inherent in the directives Congress gave the EPA in CAA section 136(h). The EPA also notes that, as discussed in Section I.E of this preamble, Congress also provided other provisions under CAA section 136, outside the scope of this rulemaking, that were intended to be and may provide incentives; for example, CAA section 136 provides $1.55 billion in incentives for various specified purposes related to CH4 mitigation and monitoring, including through grants, rebates, contracts, loans, and other activities.</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter supported the proposed reporting requirements for other large release events and supported provisions ensuring that reporters can only exclude from reported emissions those coming from third-party notifiers when the reporter provides valid, well-documented reasons for doing so. To do this, according to the commenter, the reporter should be required to submit evidence of a site survey occurring shortly after the notification proving that the event did not occur or come from their site, including time-stamped parametric data from the site showing that normal operating conditions existed. If there is imagery that clearly shows an event at the reporter's site with a quantified, time-stamped emission rate, it should not be rebuttable by the reporter according to this commenter. Several commenters stated that the EPA's proposed reporting requirements for other large release events are nearly identical to the proposed super-emitter response program reporting requirements in NSPS OOOOb and EG OOOOc. According to these commenters, reporting elements such as the unique notification identification number under the Super-Emitter Program, latitude/longitude of release, a description of the technology or method used to identify the release, and the total number of super-emitter release notifications received from a third-party for the facility have no bearing or impact on the reporting of GHG emissions. According to these commenters, GHGRP reporters should not have to bear the burden of retransmitting that information through a separate reporting program as it is already being provided to the EPA through the NSPS program.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         As noted previously in this section, we are limiting from proposal the responsibilities of facilities to respond to third-party notifications, but we are finalizing many of the proposed reporting requirements in 40 CFR 98.236(y)(11) for other large release event reporting pertaining to Super-Emitter Program (under the final NSPS OOOOb and EG OOOOc) notifications that come from the EPA. We are finalizing reporting requirements under subpart W for reporters to indicate the results of any assessment or investigation triggered by the notification, including the type of event and whether the identified emissions are included in the subpart W report for a specific source type or as an other large release event. We are clarifying in the final rule that facilities must quantify and include in the facility's annual emissions report emissions events identified in Super-Emitter Program notices received from the EPA (and the EPA has not determined that the notification contains a demonstrable error) unless the owners and operators can certify that the facility does not own or operate the equipment at the location identified in the notification or, in situations where there are multiple facilities that own and operate equipment at the location identified in the notification, the owners and operators can certify that their facility does not own or operate the emitting equipment at the location identified in the notification if they complete certain actions. We are finalizing additional requirements at 40 CFR 98.233(y)(6) for the actions required by the owners and operators in order for to certify that their facility does not own or operate the emitting equipment in cases where there are multiple oil and gas facilities within 50 meters of the location identified in the notification. Specifically, owners and operators must conduct investigations of available data as specified in 40 CFR 60.5371b(d)(2)(i) through (iv) to identify the emissions source related to the event notification within 5 days of receiving the notification. If these investigations do not identify the emissions source, owners and operators must conduct a complete leak survey of their equipment within 50 meters of the location identified in the notification using any one of methods provided in 40 CFR 98.234(a)(1) through (3) within 15 days of receiving the notification. If that survey also fails to identify the emissions source, the facility may certify that they took these required actions and that they do not own or operate the emitting equipment at the location identified in the notification. Note that, if the reporter owns and operates the equipment at the location identified in the notification and there are no other owners or operators of equipment at the location identified in the notification, then that reporter must account for the emissions from that event within their subpart W report. With respect to reporting requirements, if the emissions are not included in the subpart W report, we are finalizing a reporting requirement that the facility must have determined, and then must certify, that the emissions identified in the notification were not from assets under common ownership or control of the facility. In this manner, we are requiring that the emissions from all notifications be accounted for within the subpart W report unless the facility can demonstrate that it does not own or 
                        <PRTPAGE P="42087"/>
                        operate the equipment or, if applicable, the emitting equipment at the location identified in the notice from the EPA.
                    </P>
                    <P>As previously noted in this section, we are also finalizing that only for each EPA notification received via the Super-Emitter Program for which the EPA has not determined that the notification contains a demonstratable error, the facility would be required to report information related to the notification. We note, however, that because the EPA will have vetted and sent to the notifications through the Super-Emitter Program, we expect that demonstrable errors will be rare.</P>
                    <P>Because all Super-Emitter Program notifications will be coming from the EPA for the subpart W other large release event reporting requirements, we have reduced the reporting requirements under 40 CFR 98.236(y)(11) to focus on those details that the EPA would not already have regarding the super-emitter event. Specifically, we are eliminating from the final rule proposed reporting requirements for latitude and longitude in the notification [at 40 CFR 98.236(y)(11)(ii)] and information on the notifier and method used to detect emissions by the notifier [at 40 CFR 98.236(y)(11)(iv)]. We maintain that the remaining reporting elements are important for understanding which releases are reported as other large release events and which are reported under other provisions of subpart W.</P>
                    <HD SOURCE="HD2">C. New and Additional Emission Sources</HD>
                    <P>Sources of emissions that are required to be reported to subpart W are listed in 40 CFR 98.232 for each industry segment, with the methodology and reporting requirements for each source provided in 40 CFR 98.233 and 98.236, respectively. The EPA is finalizing as proposed the addition of several emission sources that are anticipated to have a meaningful impact on reported emissions, are commonplace in the oil and gas industry, and/or have existing emission calculation methodologies and reporting provisions in the current subpart W regulatory text. For some of these emission sources, discussed in additional detail in section III.C.1. of this preamble, reporting is currently required for some, but not all, industry segments in which they exist. Other emission sources, discussed in additional detail in sections III.C.2 through 5 of this preamble, are not currently required to be reported for any industry segments in which they exist. The addition of sources to subpart W is expected to enhance the overall quality of the data collected under the GHGRP and improve the accuracy of total emissions reported from facilities, consistent with section II.A. of this preamble.</P>
                    <P>The following sections detail the final additions of emission sources to subpart W.</P>
                    <HD SOURCE="HD3">1. Current Subpart W Emission Sources Proposed for Additional Industry Segments</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        Upon review of the U.S. GHG Inventory and the 2021 API Compendium, as well as other publications,
                        <FTREF/>
                        <SU>20</SU>
                         the EPA determined that several of the emission sources included in at least one industry segment in subpart W are not currently required to be reported by facilities in all the industry segments in which those sources exist. As such, consistent with section II.A. of this preamble, we are finalizing as proposed the addition of requirements to report CO
                        <E T="52">2,</E>
                         CH
                        <E T="52">4,</E>
                         and nitrous oxide (N
                        <E T="52">2</E>
                        O) emissions (as applicable for the source type) from the following sources under 40 CFR 98.232 and 98.236(a): 
                        <SU>21</SU>
                        <FTREF/>
                    </P>
                    <FTNT>
                        <P>
                            <SU>20</SU>
                             For example, American Petroleum Institute (API). 
                            <E T="03">Liquefied Natural Gas (LNG) Operations Consistent Methodology for Estimating Greenhouse Gas Emissions.</E>
                             Prepared for API by The LEVON Group, LLC. Version 1.0, May 2015. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>21</SU>
                             It should be noted that the EPA did not identify any subpart W emission sources missing from the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment.
                        </P>
                    </FTNT>
                    <P>• Onshore petroleum and natural gas production: Blowdown vent stacks.</P>
                    <P>• Onshore natural gas processing: Natural gas pneumatic device venting, Hydrocarbon liquids and produced water storage tank emissions.</P>
                    <P>• Onshore natural gas transmission compression: Dehydrator vents.</P>
                    <P>• Underground natural gas storage: Dehydrator vents, Blowdown vent stacks, Condensate storage tanks.</P>
                    <P>• LNG storage: Blowdown vent stacks, Acid gas removal unit vents.</P>
                    <P>• LNG import and export equipment: Acid gas removal unit vents.</P>
                    <P>• Natural gas distribution: Natural gas pneumatic device venting, Blowdown vent stacks.</P>
                    <P>• Onshore natural gas transmission pipeline: Equipment leaks at transmission company interconnect metering-regulating stations, Equipment leaks at farm tap and/or direct sale metering-regulating stations, Transmission pipeline equipment leaks.</P>
                    <P>
                        We are also finalizing several revisions that would facilitate implementation of the final provisions that require reporting of these emission sources from additional industry segments. We are finalizing revisions as proposed to change the name of the emission source type “onshore production and onshore petroleum and natural gas gathering and boosting storage tanks” to “hydrocarbon liquids and produced water storage tanks” and change “storage tank vented emissions” to “hydrocarbon liquids and produced water storage tank emissions” throughout subpart W. Additionally, we are finalizing revisions as proposed to the emission source type name in 40 CFR 98.233(k) and 98.236(k) from “transmission storage tanks” to “condensate storage tanks.” 
                        <SU>22</SU>
                        <FTREF/>
                    </P>
                    <FTNT>
                        <P>
                            <SU>22</SU>
                             Revisions are also finalized as proposed to 40 CFR 98.232(e)(3) to reference the source as “condensate storage tanks.”
                        </P>
                    </FTNT>
                    <P>We are also finalizing revisions to the calculation methodologies and/or emissions reporting structure for each of these emission source/industry segment combinations that would be needed in 40 CFR 98.233 and 98.236, respectively. For industry segments for which we are finalizing provisions to additionally require reporting of emissions from AGR vents, dehydrator vents, hydrocarbon liquids and produced water storage tank emissions, and condensate storage tank emissions, we are finalizing as proposed that reporters would use the same calculation methods and report the same information as reporters in the industry segments in which those source types are already reported. The remainder of this section describes additional amendments to 40 CFR 98.233.</P>
                    <P>For the addition of natural gas pneumatic device venting as an emission source for the Onshore Natural Gas Processing industry segment, we are finalizing as proposed that those facilities would use the calculation methodologies as described in section III.E. of this preamble. For any reporters to the Onshore Natural Gas Processing industry segment that would use Calculation Methodology 3, we are finalizing as proposed the use of the same emission factors as those used for the Onshore Natural Gas Transmission Compression and Underground Natural Gas Storage industry segments. See section III.E. of this preamble for additional details about the calculation methodologies for natural gas pneumatic devices.</P>
                    <P>
                        As noted earlier in this section, we are finalizing the addition of blowdown vent stack reporting as proposed for the Onshore Petroleum and Natural Gas Production, Underground Natural Gas Storage, LNG Storage, and Natural Gas Distribution industry segments. Subpart 
                        <PRTPAGE P="42088"/>
                        W currently requires reporting of blowdowns either using flow meter measurements (existing 40 CFR 98.233(i)(3)) or using unique physical volume calculations by equipment or event types (existing 40 CFR 98.233(i)(2)). To allow reporters in the new industry segments to calculate emissions by equipment or event types, the EPA is finalizing as proposed the specification of the appropriate list of equipment or event types for each new segment. We are finalizing as proposed that facilities in the Onshore Petroleum and Natural Gas Production, Underground Natural Gas Storage, and LNG Storage industry segments following the methodology in 40 CFR 98.233(i)(2) are required to categorize blowdown vent stack emission events into the seven categories provided in 40 CFR 98.233(i)(2)(iv)(A), as the types of blowdown vent stack emission events for these segments are similar to those for the segments currently required to categorize under this provision. We are finalizing as proposed that facilities in the Natural Gas Distribution industry segment are required to categorize blowdowns into the eight categories listed in proposed 40 CFR 98.233(i)(2)(iv)(B), as the types of blowdowns that occur in the Natural Gas Distribution industry segment are pipeline blowdowns similar to those in the Onshore Natural Gas Transmission Pipeline industry segment. After consideration of public comments, we are also finalizing two revisions to 40 CFR 98.233(i) to provide additional provisions for Natural Gas Distribution blowdowns. First, we are revising 40 CFR 98.233(i) to specify that blowdowns in the Natural Gas Distribution industry segment with a unique physical volume of less than 500 cubic feet are not required to be reported, due to the fact that distribution mains and services operate at much lower pressures than other pipelines. Second, we are revising 40 CFR 98.233(i)(1) to require the calculation of the distribution pipeline unique physical volume in cases where a pipeline does not have isolation valves and revising the definition of the term “V” in equation W-14A and “V
                        <E T="52">p</E>
                        ” in equation W-14B to remove the phrase “between isolation valves.”
                    </P>
                    <P>We are finalizing one other amendment as proposed related to the calculation of emissions from blowdown vent stacks. The EPA previously determined that for reporters in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment using the methodology provided in existing 40 CFR 98.233(i)(2) and equation W-14A, it is reasonable to allow engineering estimates based on best available information when determining temperature and pressure for emergency blowdowns, due to the geographically dispersed nature of the facilities in this industry segment. As discussed in section III.J.3. of this preamble, we are finalizing as proposed to also allow engineering estimates based on best available information when determining temperature and pressure for emergency blowdowns for the Onshore Natural Gas Transmission Pipeline industry segment, as facilities in this industry segment are also geographically dispersed. Due to the fact that facilities in the Onshore Petroleum and Natural Gas Production and Natural Gas Distribution industry segments are similarly geographically dispersed, we are finalizing as proposed that reporters in those industry segments using the methodology provided in 40 CFR 98.233(i)(2) and equation W-14A would also be allowed to use engineering estimates based on best available information available when determining temperature and pressure for emergency blowdowns.</P>
                    <P>
                        For the Onshore Natural Gas Transmission Pipeline industry segment, as noted earlier in this section, we are finalizing the addition of reporting of emissions from equipment leaks from transmission pipelines, transmission company interconnect metering-regulating stations, and farm tap and/or direct sale stations. The EPA is finalizing as proposed the addition of these sources to the calculation methodologies provided in 40 CFR 98.233(r) using population emission factors, with associated updates to the variable definitions in equation W-32A to include components in the Onshore Natural Gas Transmission Pipeline industry segment. We are also finalizing the addition of default CH
                        <E T="52">4</E>
                         population emission factors for the components specified in this paragraph at facilities in the Onshore Natural Gas Transmission Pipeline industry segment in table W-5 to subpart W as proposed. The EPA derived these final emission factors using the 1996 Gas Research Institute (GRI)/EPA study 
                        <E T="03">Methane Emissions from the Natural Gas Industry</E>
                         (hereafter referred to as “the 1996 GRI/EPA study”), specifically Volumes 9 and 10.
                        <SU>23</SU>
                        <FTREF/>
                         The precise derivation of the final emission factors is discussed in more detail in the subpart W TSD, available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                    </P>
                    <FTNT>
                        <P>
                            <SU>23</SU>
                             
                            <E T="03">Methane Emissions from the Natural Gas Industry, Volume 9: Underground Pipelines, Final Report</E>
                             (GRI-94/0257.26 and EPA-600/R-96-080i) and 
                            <E T="03">Volume 10: Metering and Pressure Regulating Stations in Natural Gas Transmission and Distribution, Final Report</E>
                             (GRI-94/0257.27 and EPA-600/R-96-080j). Gas Research Institute and U.S. Environmental Protection Agency. June 1996. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        After consideration of comments and consistent with CAA section 136(h) and the overall intent of this rulemaking for reporting to be based on empirical data, we are also providing the option for facilities to survey equipment components, measure leaks, and report the resulting emissions for transmission company interconnect metering-regulating stations and farm tap and/or direct sale stations using the equipment leak survey method in 40 CFR 98.233(q)(3). For the leak survey option, we are finalizing that a leak survey for transmission company interconnect metering-regulating stations and farm tap and/or direct sale stations will be considered a complete leak survey for the purposes of subpart W if all the subject equipment leak components at a station are included. We are finalizing this characterization of a complete leak survey such that a facility could survey some stations and utilize the population count method at other stations so long as every station quantifies equipment leak emissions using one of the provided methods in 40 CFR 98.233(q) or (r). This approach is consistent with the approach taken in this final rule for facilities in the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments that elect to conduct leak surveys in accordance with the provisions of 40 CFR 98.233(q) (see section III.P.3. of this preamble). For the leak survey method in 40 CFR 98.233(q), we are also finalizing that transmission pipeline facilities can develop a facility-specific leaker factor in accordance with 40 CFR 98.233(q)(4) using the leak measurements obtained in accordance with 40 CFR 98.233(q)(3). This approach is consistent with the approach for other industry segments subject to 40 CFR 98.233(q) who elect to conduct leak measurements in accordance with 40 CFR 98.233(q)(3). As explained in more detail in section III.P.4. of this preamble, the facility-specific leaker factor approach requires facilities to accumulate at least 50 measurements by component type to calculate the facility-specific leaker factor to ensure a statistically robust emission factor and accurate accounting of emissions. In response to comments, we are also finalizing a definition for the term “transmission company interconnect 
                        <PRTPAGE P="42089"/>
                        metering-regulating station” as well as correcting some cross-referencing errors and making minor technical corrections in the final provisions.
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed addition of existing emission source types for various industry segments.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters noted that distribution pipelines operate at pressures much lower than transmission pipelines, and as a result, the volume of gas blown down and emissions from a 50 cubic foot section of distribution pipe would be significantly less than the volume of gas and emissions from a transmission pipeline blowdown. One commenter noted that pressures are about a factor of 10 less than transmission pipelines, so blowdowns of equipment less than 500 cubic feet (rather than 50 cubic feet) should be exempt from reporting.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         To evaluate this comment, the EPA reviewed the memorandum documenting the development of the 50 cubic foot threshold, 
                        <E T="03">Equipment Threshold for Blowdowns.</E>
                        <SU>24</SU>
                        <FTREF/>
                         The analysis in that memorandum was based on the volume of emissions from a typical large processing or transmission compressor operating at a pressure of 750 psig to 800 psig. In contrast, distribution systems operate at lower pressures, with gas mains typically averaging around 60 psig and small service lines that deliver gas to individual homes operating as low as 0.25 psig.
                        <SU>25</SU>
                        <FTREF/>
                         Therefore, because the distribution pipeline operating pressures are about a factor of 10 less than the equipment upon which the 50 cubic foot threshold was based, we are finalizing a threshold of 500 cubic feet for blowdowns in the Natural Gas Distribution industry segment.
                    </P>
                    <FTNT>
                        <P>
                            <SU>24</SU>
                             U.S. EPA, 
                            <E T="03">Equipment Threshold for Blowdowns,</E>
                             November 2010. Available as EPA-HQ-OAR-2009-0923-3581 and in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>25</SU>
                             American Gas Foundation, 
                            <E T="03">Safety Performance and Integrity of the Natural Gas Distribution Infrastructure,</E>
                             January 2005. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter stated that isolation valves are uncommon in the distribution segment, so it is not possible to derive a unique physical volume, and without a unique physical volume, equations W-14A and W-14B are each missing required inputs. The commenter stated that distribution line dig-in emissions are typically mitigated by pinching off the pipeline until a full repair can be completed.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA agrees that the requirements in 40 CFR 98.233(i)(1) for calculating unique physical volume do instruct reporters to calculate the volume between isolation valves. However, lack of isolation valves does not mean that reporters cannot calculate the physical volume of the pipeline that was isolated from operation. For example, the commenter indicated that operators typically pinch off both ends of the section of pipeline that needs repair. In this case, the reporter could use the diameter of the pipeline and the distance between the two points where the pipeline is pinched off to determine the physical volume of that section of pipeline. Therefore, we have revised 40 CFR 98.233(i)(1) to specify that for natural gas distribution pipelines without isolation valves, reporters should calculate the unique physical volume of the distribution pipeline that was isolated from operation using engineering estimates based on best available data. For other industry segments with isolation valves, the “unique physical volume” does not change and can be calculated prior to any blowdowns, so that the reporter knows which unique physical volumes are 50 cubic feet or greater. While a natural gas distribution reporter may not have isolation valves to pre-define a permanent unique physical volume, the reporter can determine, for each pipeline diameter they operate, what length of pipeline would result in a physical volume of 500 cubic feet or more. If the distance between the two points where the pipeline is pinched off for a repair is greater than that length, the blowdown would be required to be reported.
                    </P>
                    <P>
                        We are also amending the definitions of the term “V” in equation W-14A and “V
                        <E T="52">p</E>
                        ” in equation W-14B to remove the phrase “between isolation valves” to account for this alternative pipeline isolation method for natural gas distribution pipelines. We note that the equations W-14A and W-14B are intended to calculate emissions for each unique physical volume, allowing for the summation of multiple blowdowns from one unique physical volume. Because the pinch-off points are not likely to be in the same location every time, reporters may have to calculate emissions from each blowdown separately. In other words, the term “N,” the number of occurrences of blowdowns for each unique physical volume in the calendar year, will most likely be equal to 1 for each “unique physical volume.”
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters requested that direct measurement be provided as an option for transmission interconnect meter-regulating stations and farm tap/direct sale stations. Commenters stated that providing a measurement option would result in improved accuracy of the emissions estimates for these emission sources and align with the objectives in the IRA to use empirical data. Commenters also explained that the current measurement methods could be used with the components on these stations. Some commenters suggested that companies could survey their stations using the existing subpart W methods and apply leaker factors for detected leaks in proposed table W-4 to subpart W, which are provided for transmission and underground storage stations, since the component types are similar. The commenter also suggested that facilities could perform annual surveys of their stations or the EPA could provide an option to survey stations over a multi-year survey cycle.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         As noted by the commenters, the only option provided in the 2023 Subpart W Proposal for transmission company interconnect metering and regulating stations and direct sale or farm tap stations was the population count method, which requires the count of stations and the use of a default population count emission factor developed using data from the 1996 GRI/EPA studies. In this rulemaking, the EPA seeks to provide calculation methods for equipment leaks from subject emission sources that are supported by available data or by providing reporters with a direct measurement option, where appropriate. Providing these options allows facilities to determine which method may be most appropriate to accurately estimate emissions while factoring the burden of the method. Generally, it is understood that direct measurement would provide the most accurate estimate of emissions, but could require significant resources to perform surveys depending on the survey method and the number of emission sources. Similarly, the use of a default population count emission factor does not provide the same level of accuracy as direct measurement, but requires lower burden (
                        <E T="03">e.g.,</E>
                         count of stations and annual operating times) to estimate emissions. The EPA's ability to provide the leaker method and the population count method for estimating equipment leaks from emission sources requires the development of default leaker or default population count emission factors. The development of these emission factors is dependent 
                        <PRTPAGE P="42090"/>
                        upon the availability of study data from which they can be derived.
                    </P>
                    <P>
                        We agree with commenters that equipment leak components at transmission company interconnect metering and regulating stations or direct sale or farm tap stations could be surveyed and directly measured using one of the methods provided in 40 CFR 98.234(a). Therefore, we are finalizing amendments in 40 CFR 98.232(m), 98.233(q), and 98.236(q) to provide that transmission pipeline companies may survey, measure, quantify and report equipment leaks from components (
                        <E T="03">i.e.,</E>
                         valves, connectors, open ended lines, pressure relief valves, and meters) at transmission company interconnect metering and regulating stations or direct sale or farm tap stations using the methods in 40 CFR 98.234(a). We are finalizing that a leak survey for transmission company interconnect metering-regulating stations and farm tap and/or direct sale stations will be considered a complete leak survey for the purposes of subpart W if all the subject equipment leak components at a station are included. We are not requiring the use of the leak survey and measurement method in 40 CFR 98.233(q), rather it will be an option in addition to the population count method. Separately, we are finalizing as proposed the station level default population count emission factors in 40 CFR 98.233(r), as discussed in section III.Q. of this preamble.
                    </P>
                    <P>
                        However, at this time, the EPA does not have the data necessary to provide a default leaker emission factor approach for equipment leaks from stations at transmission pipeline companies (
                        <E T="03">i.e.,</E>
                         transmission company interconnect metering and regulating stations; direct sale or farm tap) as the commenters have requested. While one commenter suggests that transmission pipeline companies could utilize the leaker emission factors in table W-4 to subpart W with the count of leakers at transmission company interconnect metering and regulating stations and direct sale or farm tap stations, based on our assessment, we find that the leaker emission factors in table W-4 may not be representative of the leaks from these transmission pipeline emission sources. The emission factors in table W-4 were developed and intended for components at transmission compressor stations and underground natural gas storage stations. Therefore, we are not finalizing a leaker approach for these emission sources that would use a default leaker emission factor, but we may consider providing this approach in a future rulemaking if data becomes available that could inform a default leaker emission factor set.
                    </P>
                    <P>
                        We also reviewed the 1996 GRI/EPA study upon which the final default population count factors for transmission company interconnect metering and regulating stations and direct sale or farm tap stations are based to determine if a default leaker emission factor could be derived from the study data. However, the study data are presented as station-level leaks rates (
                        <E T="03">i.e.,</E>
                         scf/station-day). Component level leak rates were not provided in the study. Component level leak rates are needed to develop default leaker emission factors analogous to those in Subpart W for other equipment leak emissions sources.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters stated that the EPA should provide additional flexibility in the quantification of emissions from transmission pipelines, including allowing a leaker emission factor approach and/or direct measurement of leak emissions.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA evaluated potential empirical methods for quantifying transmission pipeline leaks and determined that there is insufficient data available to develop subpart W methods that either directly quantify emissions or apply leaker emission factors to detected leaks. Although we are not aware of any published studies that include transmission pipeline leak data, Yu 
                        <E T="03">et al.</E>
                         (2022) 
                        <SU>26</SU>
                        <FTREF/>
                         used quantitative aerial remote sensing surveys to quantify gathering pipeline leaks with emission rates greater than 10 to 20 kilograms of CH
                        <E T="52">4</E>
                         per hour. Quantitative aerial remote sensing theoretically could be used to quantify transmission pipeline leak emissions but a direct method based on quantitative remote sensing would have very high uncertainty due to lack of data on the emission rate distribution of transmission pipeline leaks. Directly quantifying emissions would exclude an unknown fraction of total emissions that were below the survey method's detection limit. Similarly, we evaluated the available data to determine whether a leaker factor approach could be developed. As noted above, we are not aware of appropriate data for developing leaker factors for transmission pipelines. We also note that the accuracy of leaker emission factors is dependent on the method detection limit and therefore likely would need to be specific to each survey approach. The EPA intends to evaluate any data available in the future on transmission pipeline leak emission rates and determine if an empirical method can be incorporated in future updates. Another issue with quantitative remote sensing is that individual measurements of leak emission rates can have high uncertainty. Repeat measurements reduce the uncertainty, but it is not currently clear what methodology, including number of measurements, would be appropriate for accurately estimating emissions from transmission pipeline leaks. The EPA also intends to evaluate future pipeline leak data to determine what level of uncertainty and/or number of measurements is needed to accurately quantify emissions.
                    </P>
                    <FTNT>
                        <P>
                            <SU>26</SU>
                             Yu, J., 
                            <E T="03">et al.</E>
                             “Methane Emissions from Natural Gas Gathering Pipelines in the Permian Basin.” 
                            <E T="03">Environ. Sci. Technol. Lett.</E>
                             2022, 9, 969-974. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters requested clarification of the proposed terms: Interconnect, Farm Tap and Direct Sale. The commenters requested that the EPA either provide definitions and examples of these terms in the regulatory text or in a FAQ document.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The term “Farm Tap” is already defined in 40 CFR 98.238. The definition provided is, “
                        <E T="03">Farm Taps</E>
                         are pressure regulation stations that deliver gas directly from transmission pipelines to generally rural customers. In some cases, a nearby LDC may handle the billing of the gas to the customer(s).” We note in the rule that table W-5 to subpart W groups “Direct Sale or Farm Tap Station” indicating that we expect the terms to be interchangeable or sufficiently carrying the same meaning, that is a station where there is a direct connect (
                        <E T="03">i.e.,</E>
                         sale) from the transmission pipeline to the customer.
                    </P>
                    <P>
                        In reviewing Volume 10 of the 1996 GRI/EPA study upon which the final default population count emission factors are based, we find that the emission factor included in table W-5 for “Transmission Company Interconnect M&amp;R Station” is based on data collected from stations, which are “interconnects with other transmission companies to allow for flexibility of supply. The stations can flow in either direction.” The 1996 GRI/EPA study specifically excludes transmission stations where gas is delivered to distribution companies as these are covered in the distribution segment, just as they are in subpart W where natural gas distribution companies report equipment leak emissions from transmission-distribution transfer stations. The “Transmission Company Interconnect M&amp;R Station” is intended to be stations that are transmission-to-transmission interconnect points. Furthermore, these stations are characterized in the 1996 GRI/EPA study as performing metering and 
                        <PRTPAGE P="42091"/>
                        pressure regulating with an inlet pressure above 100 psig. In order to provide clarity to the meaning of the term “Transmission Company Interconnect M&amp;R Station”, we are finalizing the following definition in 40 CFR 98.238: 
                        <E T="03">Transmission Company Interconnect M&amp;R Station</E>
                         means a metering and pressure regulating station with an inlet pressure above 100 psig located at a point of transmission pipeline to transmission pipeline interconnect.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters pointed out that there was a mismatch between equation W-32A and the emission factors provided in table W-5 to subpart W. Commenters stated that the emission factors provided in table W-5 are default methane population emission factors. Commenters stated that the variable “GHGi” for transmission pipeline sources provided in 40 CFR 98.233(r) was proposed as equaling 0.975 for CH
                        <E T="52">4</E>
                         and 0.011 for CO
                        <E T="52">2</E>
                        . Commenters requested that the EPA revise the equation or the factors for consistency and clarity.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We agree with commenters that there was an inadvertent error in adding onshore natural gas transmission pipeline to the list of sources in the variable “GHGi” of equation W-32A in 40 CFR 98.233(r). We are finalizing a correction that will move the addition of “onshore natural gas transmission pipeline” to be grouped with a methane concentration of 1 and a carbon dioxide concentration value of 0.011 in the variable “GHGi” of equation W-32A in 40 CFR 98.233(r), consistent with the application of the default methane emission factors, which we are finalizing as proposed.
                    </P>
                    <HD SOURCE="HD3">2. Nitrogen Removal Units</HD>
                    <P>
                        The EPA is finalizing as proposed revisions to 40 CFR 98.232, 98.233(d), and 98.236(d) to add calculation and reporting requirements for CH
                        <E T="52">4</E>
                         emissions from nitrogen removal units used in the Onshore Petroleum and Natural Gas Production, Onshore Natural Gas Processing, Onshore Petroleum Natural Gas Gathering and Boosting, LNG Storage, and LNG Import and Export Equipment industry segments. Nitrogen removal units remove nitrogen from the raw natural gas stream to meet pipeline requirements and for compressing natural gas into LNG.
                        <FTREF/>
                        <E T="51">27 28</E>
                         The nitrogen removal unit typically follows in series after other process units that remove acid gas (
                        <E T="03">e.g.,</E>
                         CO
                        <E T="52">2</E>
                        , hydrogen sulfide), water, and heavy hydrocarbons. The EPA received only minor comments regarding the addition of nitrogen removal units. See the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
                    </P>
                    <FTNT>
                        <P>
                            <SU>27</SU>
                             Kuo, J.C., K.H. Wang, C. Chen. Pros and cons of different Nitrogen Removal Unit (NRU) technology. 7 (2012) 52-59. 
                            <E T="03">Journal of Natural Gas Science and Engineering.</E>
                             July 2012. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                        <P>
                            <SU>28</SU>
                             Park, J., D. Cho. Decision methodology for nitrogen removal process in the LNG plant using analytic hierarchy process. 
                            <E T="03">Journal of Industrial and Engineering Chemistry.</E>
                             37 (2016) 75-83. 2016. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        The EPA is finalizing as proposed the definition of “nitrogen removal unit” in 40 CFR 98.238 as a process unit that separates nitrogen from natural gas using various separation processes (
                        <E T="03">e.g.,</E>
                         cryogenic units, membrane units). The EPA is finalizing a definition of “nitrogen removal unit vent emissions” as the nitrogen gas separated from the natural gas and released with CH
                        <E T="52">4</E>
                         and other gases to the atmosphere. The proposed definition of this term also included nitrogen gas released to a flare or other combustion unit, similar to the definition of “acid gas removal unit vent emissions.” However, as described later in this section, gas from a nitrogen removal unit routed to a flare or routed to combustion will be reported separately as flared emissions or combustion emissions, respectively, so the final definition of “nitrogen removal unit vent emissions” includes only the vent gas released to the atmosphere. The EPA is finalizing as proposed the amendments to 40 CFR 98.232(c)(17), 98.232(d)(5), 98.232(g)(10), 98.232(h)(9), and 98.232(j)(3) to add nitrogen removal unit vents to the list of source types for which the industry segments previously specified will be required to report emissions and is finalizing as proposed the corresponding additions at 40 CFR 98.236(a) to add nitrogen removal units to the list of equipment and activities that will be reported for each of these industry segments.
                    </P>
                    <P>
                        The EPA is finalizing CH
                        <E T="52">4</E>
                         emission calculation methodologies for nitrogen removal units that are nearly identical to the final calculation methodologies in 40 CFR 98.233(d) for AGRs. These methods include use of vent meters, engineering calculations based upon flow rate and composition of gas streams, or calculation using simulation software. The final amendments to the AGR calculation methodologies are largely the same as proposed, with some additional clarifications regarding applicability of the calculation methods and provisions to address vents routed to vapor recovery systems. The only difference between the final calculation methodologies for CH
                        <E T="52">4</E>
                         emissions from AGRs and nitrogen removal units is that any nitrogen removal unit with a vent meter installed must use Calculation Method 2; the new provision allowing use of Calculation Method 4 for AGRs with a vent meter does not apply to nitrogen removal units. Comments on and a more detailed discussion regarding the amendments to the AGR calculation methodologies, which are relevant to nitrogen removal units calculation methodologies as well, are addressed in section III.F.1. of this preamble. Further, the EPA is finalizing as proposed the addition of relevant reporting elements for CH
                        <E T="52">4</E>
                         emissions from nitrogen removal units to 40 CFR 98.236(d) for each of the allowable calculation methodologies.
                    </P>
                    <P>
                        The EPA is finalizing as proposed the requirements that emissions from nitrogen removal unit vents routed to a flare (CO
                        <E T="52">2</E>
                        , CH
                        <E T="52">4</E>
                        , and N
                        <E T="52">2</E>
                        O) will be reported under 40 CFR 98.236(n) separately from vented nitrogen removal unit emissions (CH
                        <E T="52">4</E>
                        ). We note that, as explained in section III.N. of this preamble, the EPA is finalizing requirements for determining the flow and composition of the gas routed to a flare that differ from those proposed in 40 CFR 98.233(n) that also affect AGRs and nitrogen removal units. Under the final rule, the flared nitrogen removal unit emissions are included with “other” flared source types for purposes of the disaggregation provisions in 40 CFR 98.233(n)(10) and 40 CFR 98.236(n)(19), as proposed. See section III.N. of this preamble for more information on the flaring calculation and reporting provisions, including changes from the proposed requirements that affect AGRs and nitrogen removal units.
                    </P>
                    <HD SOURCE="HD3">3. Produced Water Tanks</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        As discussed in the 2023 Subpart W proposal, in the 2022 U.S. GHG Inventory emissions estimate for 2020, the EPA estimated approximately 140,300 metric tons of CH
                        <E T="52">4</E>
                         emissions from produced water tanks associated with natural gas wells and 88,600 metric tons of CH
                        <E T="52">4</E>
                         emissions from produced water tanks associated with oil wells. Therefore, consistent with section II.A. of this preamble, the EPA is finalizing as proposed amendments to 40 CFR 98.233(j) to require reporters with 
                        <PRTPAGE P="42092"/>
                        atmospheric pressure storage tanks receiving produced water to calculate CH
                        <E T="52">4</E>
                         emissions using any of the three calculation methodologies specified in 40 CFR 98.233(j)(1) through (3). Industry segments required to report emissions from produced water tanks would include Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, and Onshore Natural Gas Processing. The EPA is finalizing the definition of “produced water” as proposed, which is the water (brine) brought up from the hydrocarbon-bearing strata during the extraction of oil and gas, and can include formation water, injection water, and any chemicals added downhole or during the oil/water separation process.
                    </P>
                    <P>
                        For facilities with produced water storage tanks electing to model their CH
                        <E T="52">4</E>
                         emissions consistent with 40 CFR 98.233(j)(1), the EPA is finalizing revisions as proposed to allow facilities to select any software option that meets the requirements currently stated in 40 CFR 98.233(j)(1) (
                        <E T="03">i.e.,</E>
                         to select a modeling software that uses the Peng-Robinson equation of state, models flashing emissions from produced water, and speciates CH
                        <E T="52">4</E>
                         emissions that result when the produced water from the separator or non-separator equipment enters an atmospheric pressure storage tank). We are finalizing revisions to 40 CFR 98.233(j)(1) as proposed to state that API's E&amp;P Tanks should only be used for modeling atmospheric storage tanks receiving hydrocarbon liquids.
                    </P>
                    <P>For stuck dump valve emissions associated with produced water tanks, we proposed that calculation of these emissions would not be required when using Calculation Method 3. Additionally, no correction factor was proposed for use in equation W-16 to calculate stuck dump valve emissions associated with produced water tanks in Calculation Methods 2 and 3. Therefore, and after consideration of comments received, the EPA is revising from proposal the introductory paragraph in 40 CFR 98.233(j) to, at this time, only require calculation and reporting of emissions from hydrocarbon liquid stuck dump valves per 40 CFR 98.233(j)(5).</P>
                    <P>As described in section III.K.5. of this preamble, the EPA is finalizing that reporters would collect measurements of the simulation input parameters listed under 40 CFR 98.233(j)(1) for produced water tanks, with changes from proposal described in section III.K.5. of this preamble. In addition, after consideration of comments received and the technical challenges with measuring entrained oil in produced water, the EPA is finalizing updates from proposal that facilities may elect to use a representative hydrocarbon liquid composition and assume oil entrainment of 1 percent or greater rather than collecting a produced water sample.</P>
                    <P>
                        The EPA is finalizing as proposed the addition of CH
                        <E T="52">4</E>
                         emission factors to 40 CFR 98.233(j)(3) that were developed as part of the 1996 GRI/EPA study, which is consistent with the factors used by the U.S. GHG Inventory. The final emission factors were sourced from the 2021 API Compendium (table 6-26), which provides emission factors from the 1996 GRI/EPA study converted from units of million pounds per year to units of metric tons per thousand barrels (based upon the assumption of 497 million barrels of produced water annual production). Average emission factors are provided for pressures of 50, 250, and 1,000 pounds per square inch. The EPA expects that these factors, which were developed using process simulation at different pressures, are sufficiently representative of produced water tank emissions. Furthermore, the EPA is not aware of any other emission factors for produced water tank emissions, nor are we aware of studies or data that would allow us to develop different emission factors.
                    </P>
                    <P>
                        We are also finalizing reporting requirements for produced water tanks as proposed. We are finalizing revisions to 40 CFR 98.236(j)(1) as proposed to refer to both hydrocarbon liquid and produced water atmospheric storage tanks. Additionally, we are finalizing the addition of 40 CFR 98.236(j)(2) as proposed to require reporting of total annual produced water volumes for each pressure range, estimates of the fraction of produced water throughput that is controlled by flares and/or vapor recovery, counts of controlled and uncontrolled produced water tanks, and annual CH
                        <E T="52">4</E>
                         emissions vented directly to atmosphere from produced water tanks.
                    </P>
                    <P>The EPA is also finalizing as proposed the revision of the emission source type name in 40 CFR 98.233(j) and 40 CFR 98.236(j) from “onshore production and onshore petroleum and natural gas gathering and boosting storage tanks” to “hydrocarbon liquids and produced water storage tanks” to reflect the proposed addition of produced water tanks. Consistently, the EPA is also finalizing as proposed revisions to the source type provided in 40 CFR 98.232(c)(10) and 40 CFR 98.232(j)(6) to “Hydrocarbon liquid and produced water storage tank emissions,” which reflect the addition of produced water tanks.</P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to add produced water tanks as an emission source for the Onshore Petroleum and Natural Gas Production, Onshore Natural Gas Processing, and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments.</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter proposed limiting the required emission calculations for produced water tanks to emissions associated with stuck dump valves. Another commenter additionally noted that the EPA provides a stuck dump valve emission factor for produced water tanks if Calculation Method 1 or 2 is used, but no factor is provided for tanks using Calculation Method 3.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA does not agree that produced water tank emissions should be limited to only those emissions associated with stuck dump valves. In the 2022 U.S. GHG Inventory emissions estimate for 2020, the EPA estimated approximately 140,300 mt CH
                        <E T="52">4</E>
                         emissions from produced water tanks associated with natural gas wells and 88,600 mt CH
                        <E T="52">4</E>
                         emissions from produced water tanks associated with oil wells. These emissions would not be fully represented in subpart W by only requiring reporting of emissions from produced water tanks with stuck dump valves; in other words, this approach would not result in accurate reporting of total emissions.
                    </P>
                    <P>
                        As proposed, calculation of emissions from stuck dump valves per 40 CFR 98.233(j)(5) would not be required for produced water tanks using Calculation Method 3. Additionally, the EPA has reviewed the inputs to equation W-16 and notes that the correction factor, CF
                        <E T="52">dv</E>
                        , is provided for only separators in crude oil and condensate production for Calculation Methods 1 and 2. Finally, the EPA is not aware of published methodologies for estimating stuck dump valve emissions associated specifically with produced water tanks. Therefore, after consideration of comments received, the EPA is revising from proposal the introductory paragraph in 40 CFR 98.233(j) to not require at this time calculation of emissions from stuck dump valves for produced water tanks using any of the three calculation methodologies and only require calculation and reporting of emissions from hydrocarbon liquid stuck dump valves per 40 CFR 98.233(j)(5).
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Several commenters noted burden associated with collection of 
                        <PRTPAGE P="42093"/>
                        pressurized liquid samples and other measurements from produced water storage tanks. Additionally, one commenter recommended allowing operators to assume that produced water tanks contain 1 percent of the oil content. They noted that this would allow for consistency with Texas Commission on Environmental Quality (TCEQ) Emissions Representation for Produced Water guidance,
                        <SU>29</SU>
                        <FTREF/>
                         which describes that oil or condensate floats on top of the water phase and contributes to the partial pressure within the tank.
                    </P>
                    <FTNT>
                        <P>
                            <SU>29</SU>
                             
                            <E T="03">Emission Representations for Produced Water.</E>
                             Texas Commission on Environmental Quality. Available at: 
                            <E T="03">https://www.tceq.texas.gov/assets/public/permitting/air/NewSourceReview/oilgas/produced-water.pdf</E>
                             and in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        <E T="03">Response:</E>
                         The EPA is finalizing a revision from the proposal for a reduced frequency schedule for composition and Reid vapor pressure sampling and analysis from each well, separator, or non-separator equipment. Reporters must sample and analyze hydrocarbon liquids or produced water composition and Reid vapor pressure at least once every 5 years. Additional details are provided in section III.K.5. of this preamble.
                    </P>
                    <P>
                        Additionally, for produced water tanks, the EPA recognizes that industry standard is to assume one percent oil entrainment for produced water.
                        <E T="51">30 31</E>
                        <FTREF/>
                         The premise behind the one percent assumption is that entrainment from upstream separation introduces hydrocarbon liquids into the produced water tank. This entrained material forms a layer of hydrocarbons that float on top of the water in the tank and is expected to increase total emissions, and the EPA recognizes that it is technically challenging to accurately measure the entrained oil content in the water fed to the tank. Thus, facilities often use the produced water flowrate and the composition of the associated hydrocarbon streams when performing the flash emission calculations. Flash emissions from produced water tanks are then determined by multiplying the flash emission calculation results by one percent.
                    </P>
                    <FTNT>
                        <P>
                            <SU>30</SU>
                             
                            <E T="03">Id.</E>
                        </P>
                        <P>
                            <SU>31</SU>
                             
                            <E T="03">Are Produced Water Emission Factors Accurate?</E>
                             Bryan Research &amp; Engineering, Inc. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>The EPA agrees with requests from commenters that one percent entrainment is an acceptable assumption to represent flashing emissions from produced water tanks given the difficulty with accurately quantifying oil entrainment in produced water. We are therefore adding language in 40 CFR 98.233(j)(1)(vii) and 40 CFR 98.233(j)(2)(i) of the final rule that for produced water composition, reporters may elect to use a representative hydrocarbon liquid composition and assume oil entrainment of 1 percent or greater rather than collecting a produced water sample every 5 years.</P>
                    <HD SOURCE="HD3">4. Mud Degassing</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        The EPA is adding a new emission source type to subpart W for emissions from drilling mud degassing. The term “drilling mud,” also referred to as “drilling fluid,” refers to a class of viscous fluids used during the drilling of oil and gas wells. As drilling mud circulates through the wellbore, natural gas and heavier hydrocarbons can become entrained in the mud. Mud degassing refers to the practice of extracting the entrained gas from drilling mud once it is outside the wellbore. The new provisions add calculation and reporting requirements for CH
                        <E T="52">4</E>
                         emissions from mud degassing associated with well drilling for onshore petroleum and natural gas production facilities in 40 CFR 98.232(c), 98.233(dd), and 98.236(dd). In addition, several new definitions for terms related to mud degassing are being added to 40 CFR 98.238. The EPA is only requiring the reporting of CH
                        <E T="52">4</E>
                         emissions from this source because CH
                        <E T="52">4</E>
                         is the primary GHG emitted from this source, while emissions of CO
                        <E T="52">2</E>
                         are expected to be very small.
                    </P>
                    <P>The EPA is finalizing the revision to 40 CFR 98.232(c) as proposed, and the revisions to 98.233(dd) and 98.236(dd) with changes to those proposed, including the addition of a third calculation method that must be used in certain circumstances and corresponding reporting requirements, so that reporters have three calculation methods that apply as specified in those provisions to calculate emissions from mud degassing in new 40 CFR 98.233(dd).</P>
                    <P>More specifically, the final provision includes two important changes from proposal for the requirement to use Calculation Method 1 when the reporter has taken mudlogging measurements. First, the final rule adds the further qualification that Calculation Method 1 is required when measurements are taken once the first hydrocarbon bearing zone has been penetrated until drilling mud ceases to be circulated in the wellbore, because natural gas is unlikely to become entrained in drilling fluids until the first hydrocarbon zone is penetrated. Second, the final rule adds that Calculation Method 1 is required when gas-trap derived gas concentration from mudlogging measurements is reported in parts per million (ppm) or is reported in units from which ppm can be derived.</P>
                    <P>
                        Additionally, the final Calculation Method 1 includes several additional changes from proposal. We have replaced the term “at the same approximate depth” with “within the equivalent stratigraphic interval” to use more widely recognized geologic terminology and to recognize that formation properties are more directly related to stratigraphy than to depth below surface. We are also adding this term to 40 CFR 98.238, Definitions, and defining the term as “the depth of the same stratum of rock in the Earth's subsurface.” Other changes to Calculation Method 1 include clarifications in the definitions of “T
                        <E T="52">r</E>
                        ” in equations W-41 and W-42, and “T
                        <E T="52">p</E>
                        ” in equation W-43 to specify that total time that drilling mud is circulated in the well begins with initial penetration of the first hydrocarbon-bearing zone rather than when the well is spudded at the surface, and until drilling mud ceases to be circulated in the wellbore. We are also amending the term X
                        <E T="52">n</E>
                         in equation W-41 to be the “average” gas concentration. The use of the average gas concentration should ensure consistency with the use of the average mud rate in equation W-41 and result in emissions calculations that are representative of average conditions throughout the drilling cycle.
                    </P>
                    <P>
                        Consistent with the proposal, the final Calculation Method 1 requires the reporter to calculate CH
                        <E T="52">4</E>
                         emissions and a CH
                        <E T="52">4</E>
                         emissions rate from mud degassing for a representative well and then to apply that rate to other wells in the sub-basin and within the equivalent stratigraphic interval. To qualify as a representative well, we are finalizing that the well is required to be drilled in the same sub-basin and within the equivalent stratigraphic interval from the surface (instead of at the same approximate total depth, as proposed) as the wells for which it is representative.
                    </P>
                    <P>
                        Under the final provisions, as proposed, the operator is required to identify and calculate natural gas emissions for a representative well at least once every 2 years for each sub-basin and equivalent stratigraphic interval within the facility to ensure that the emissions from representative wells are representative of the operating and drilling practices within each applicable sub-basin in the facility. In the first year of reporting, however, the operator may use measurements from the prior 
                        <PRTPAGE P="42094"/>
                        reporting year if measurements from the current reporting year are not available.
                    </P>
                    <P>
                        Under the final provisions, if mudlogging measurements were not taken or were taken but did not produce gas concentration in ppm or in units from which ppm can be derived, reporters must use Calculation Method 2 to determine emissions from mud degassing using equation W-44, which incorporates the nationwide emission factors provided by the CenSARA study.
                        <SU>32</SU>
                        <FTREF/>
                         Specifically, emissions are calculated using an emission factor of 0.2605 mt CH
                        <E T="52">4</E>
                         per drilling day per well for water-based mud and a factor of 0.0586 mt CH
                        <E T="52">4</E>
                         per drilling day per well for oil-based and synthetic drilling muds. After consideration of comments, the EPA is finalizing Calculation Method 2 with two notable changes from the proposal. The final equation W-44 now includes an adjustment to local conditions by taking the ratio of the local CH
                        <E T="52">4</E>
                         mole fraction, which will consist of the average mole fraction of CH
                        <E T="52">4</E>
                         in produced gas for the sub-basin reported under 40 CFR 98.236(aa)(1)(ii)(I), (X
                        <E T="52">CH4</E>
                        ), to the nationwide mole fraction of 83.35 used to derive the emission factors. This adjustment for local conditions will more accurately reflect facility-specific emissions compared to relying solely on nationwide emission factors as originally proposed. The second change affects the number of drilling days, DD
                        <E T="52">p</E>
                        , in equation W-44. Entrainment of gas in drilling mud and resulting emissions are unlikely if mud is not circulating, which can occur for many reasons during the drilling of a well; for example, if drilling ceases due to a well workover, implementation of health and safety protocols, equipment failure, or for other reasons. Therefore, in the final rule, the number of drilling days used in equation W-44 is the actual number of days drilling mud is circulated in the wellbore.
                    </P>
                    <FTNT>
                        <P>
                            <SU>32</SU>
                             2011 
                            <E T="03">Oil and Gas Emission Inventory Enhancement Project for CenSARA States.</E>
                             Produced by ENVIRON International Corporation for Central States Air Resources Agencies. November 2011. Available at 
                            <E T="03">https://www.deq.ok.gov/wp-content/uploads/air-division/EI_OG_Final_Report_CenSara_122712.pdf</E>
                             and in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>In addition to the two calculation methods that were proposed, we are finalizing Calculation Method 3, which must be used when mudlogging measurements are taken during some, but not all, of the time the well bore has penetrated the first hydrocarbon bearing zone and until drilling mud ceases to be circulated in the wellbore. Under Calculation Method 3, Calculation Method 1 must be used to calculate emissions for the cumulative amount of time mudlogging measurements were taken and Calculation Method 2 must be used for the cumulative amount of time mudlogging measurements were not taken. The emissions derived from each are added together for Calculation Method 3.</P>
                    <P>In addition to the calculation requirements, the EPA is finalizing corresponding reporting requirements for emissions by well in 40 CFR 98.236(dd) as proposed, except that reporters using Calculation Method 1 must report the target hydrocarbon-bearing stratigraphic formation to which the well is drilled in addition to the total vertical depth of the well to allow for adequate verification of reported mud degassing emissions. We have added a definition for target hydrocarbon-bearing stratigraphic formation in 40 CFR 98.238 to mean the stratigraphic interval intended to be the primary hydrocarbon producing formation. The final reporting requirements for mud degassing also include reporting requirements for reporters using Calculation Method 3, which require the reporter to indicate if this method was used and to report the required Calculation Method 1 data elements for the time periods when Calculation Method 1 was used and the required Calculation Method 2 data elements when Calculation Method 2 was used.</P>
                    <P>
                        The other change from the proposed reporting requirements affects several data elements in Calculation Method 1, based on the EPA's review and consideration of public comments. The EPA proposed that all of the Calculation Method 1 data elements identified as inputs to emission equations should be directly reported without a 2-year delay. In the final rule, there are several Calculation Method 1 inputs to emission equations for which reporting may be delayed by 2 years. Specifically, the Average concentration of natural gas in the drilling mud (X
                        <E T="52">n</E>
                        ), the Measured mole fraction of CH
                        <E T="52">4</E>
                         the natural gas (GHG
                        <E T="52">CH4</E>
                        ), and the Total time that drilling mud is circulated in the well (T
                        <E T="52">r</E>
                         in equations W-41 and W-42 and T
                        <E T="52">p</E>
                         in equation W-43) are eligible for the 2-year delay for any well that is a wildcat and/or delineation well. The 2-year delay is also available for the Average mud rate (MR
                        <E T="52">r</E>
                        ) and the Calculated CH
                        <E T="52">4</E>
                         emissions rate (ER
                        <E T="52">sCH4,r</E>
                        ) when one or more wells to which the calculated CH
                        <E T="52">4</E>
                         emissions rate for the representative well (ER
                        <E T="52">s,CH4,r</E>
                         in equation W-42) is applied is a wildcat and/or delineation well. In addition, reporting of the Total time that drilling mud is circulated in the well (Tr in equations W-41 and W-42) may be delayed for 2 years for the representative well if one or more wells to which the calculated CH
                        <E T="52">4</E>
                         emissions rate for the representative well (ER
                        <E T="52">s,CH4,r</E>
                         in equation W-42) is applied is a wildcat and/or delineation well. Wildcat and delineation wells are considered exploratory wells in the oil and gas industry, and data from these wells are generally considered sensitive information by the industry. State oil and gas commissions commonly hold such data from public release for two years. Therefore, the EPA has determined that these inputs to emission equations should be directly reported but are subject to a 2-year delay for exploratory wells to acknowledge the sensitive nature of the data and to ensure that the data cannot be back calculated prior to the end of the 2-year delay. However, we emphasize that this information would be considered to be emission data under CAA section 114 that is not eligible for confidential treatment upon submission to the agency, and thus will be made available to the public upon submission. Furthermore, emissions from any well with well degassing must still be reported annually and we further note that we have other information that will allow verification of reported emissions. Moreover, the EPA intends to be diligent in reviewing and reconciling delayed data with reported emissions data, and we also stress that, although the delayed data may not be reported in the initial reporting year, reporters must maintain records supporting their emission calculations and these records are subject to review by the EPA. Finally, the EPA intends to further evaluate whether this information will be required and, if so, may require reporting without delay in a future rulemaking.
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to add mud degassing as an emission source for onshore petroleum and natural gas production facilities.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Some commenters supported the addition of mud degassing as a source, while other commenters questioned the inclusion of mud degassing as an emissions source of CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                        , stating that the EPA has not taken due account of the difficulties and costs associated with measuring methane emissions from drilling mud degassing. In addition, one commenter suggested that the EPA has not considered the ability of reporters to 
                        <PRTPAGE P="42095"/>
                        accurately capture such emissions as required by the IRA. The commenters recommended that the EPA not finalize mud degassing in subpart W.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         At this time, we agree with the commenters that CO
                        <E T="52">2</E>
                         emissions are unlikely to be significant from this source, and the EPA did not propose and is not finalizing requirements to calculate and report CO
                        <E T="52">2</E>
                         emissions from drilling mud degassing in this final rule. Under the final provisions, only CH
                        <E T="52">4</E>
                         emissions will be reported for drilling mud degassing from the onshore production segment as the EPA considers mud degassing to be a potentially significant source of CH
                        <E T="52">4</E>
                         emissions from the onshore production segment. Several notable guidelines on oil and gas emission sources include mud degassing emissions as a source of GHG emissions and provide calculation methods for estimating mud degassing emissions from the onshore production segment, including API, the Central States Air Resources Agencies (CenSARA), and the New York State Energy Research and Development Authority (NYSERDA). The EPA further notes that CenSARA and NYSERDA guidelines use the same emission factors, which are based on a paper published by the EPA in 1977 entitled “Atmospheric Emissions from Offshore Oil and Gas Development and Production.” This paper estimated two total hydrocarbon (THC) emission factors (EFs), for water-based mud and oil-based mud degassing. Thus, we believe that it should be included as an emissions source in reporting for the onshore production segment to best ensure accurate reporting of total methane emissions from the facilities. We are, therefore, finalizing that onshore production reporters are required to report CH
                        <E T="52">4</E>
                         emissions from drilling mud degassing.
                    </P>
                    <P>
                        Regarding the commenter's assertion that the EPA has not considered the ability of reporters to accurately capture such emissions, we note that when proposing and finalizing the rule, the EPA considered the potential challenges associated with taking measurements from mud degassing. We understand that field and operational conditions may impact a reporter's ability to take measurements at the well site or there may be instances when mud logging is not used. Consistent with the proposal, the final rule does not require measurement of CH
                        <E T="52">4</E>
                         emissions from mud degassing, but only that measured data be used to calculate emissions using Calculation Method 1 if measurements are taken. When measurement data are not available, the proposed and final rule provide additional flexibility by allowing reporters to use the engineering equations in Calculation Method 2 with default emission factors for oil-based, water-based and synthetic drilling muds. In addition, as discussed in the response to comments later in this section, the EPA is providing additional flexibility by finalizing a new Calculation Method 3, which requires use of Calculation Method 1 when mudlogging measurements are taken at intermittent time periods during mud circulation while requiring use of Calculation Method 2 for those time intervals when mudlogging measurements are not taken.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         The EPA received several comments requesting clarification of the term “same approximate total depth” as it was used in the proposed rule for Calculation Method 1 and how to determine same approximate depth.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA agrees with the commenters that the term “same approximate total depth” as used in the proposed rule could be further clarified. We are finalizing the rule with the term “equivalent stratigraphic interval” instead of the proposed term “same approximate total depth” to provide more certainty to the meaning of the term. “Equivalent stratigraphic interval” is a term and concept that should be familiar to professionals in the oil and gas industry and others with a basic understanding of geology. It refers to the depth to a specific layer of rock in the Earth's subsurface. Since the depth of a specific strata can vary due to ground elevation, layer dip, or subsurface discontinuities, it is often useful to refer to the equivalent stratigraphic interval as opposed to true vertical depth, sub-sea depth or more general terms including approximate depth. More importantly, it clearly reflects the intent of the regulations in using this term, which is to measure and apply the emissions rate from a representative well to all others in the same producing formation. We also note that stratigraphic depth can be correlated with geophysical data such as seismic data. Additionally, the term “equivalent stratigraphic interval” is defined in the final rule as “the depth of the same stratum of rock in the Earth's subsurface.” In the final provisions, we have replaced “same approximate total depth” with “equivalent stratigraphic interval” where the term appeared in 40 CFR 98.233(dd) and 98.236(dd) of the proposed rule. In addition, we added the definition of equivalent stratigraphic interval to 40 CFR 98.238, Definitions. Complimentary to this change, in 40 CFR 98.236(dd)(1) of the final rule we are requiring reporters to report the target hydrocarbon-bearing stratigraphic formation for each well, including the representative well, when Calculation Method 1 is used. We have also added a definition for this term in 40 CFR 98.238 to mean the stratigraphic interval intended to be the primary hydrocarbon producing formation. This reporting requirement will allow for adequate verification of mud degassing emissions.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters stated that the EPA has proposed that operators must use mudlogging measurements taken during the reporting year, and therefore calculate emissions using Methodology 1. The commenters disagreed with this requirement, claiming that it is possible a mudlogging measurement is taken at the very early stages of a drilling operation, and that measurement may not ultimately be reflective of the entire duration of the drilling operation. The commenters recommended allowing reporters to use Calculation Method 2 for all active drilling and proposed a third option in the event that some mudlogging data is available. Commenters stated that the third option would allow operators to use a combination of the two methodologies when a varying level of directly measured data is available. Commenters stated that, in this third option, mudlogging measurements would be used based on Method 1 for the period in which the data are available, and Method 2 would be used for the remaining period of drilling activity where mudlogging data are not available.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA did not propose that operators must use mudlogging equipment, only that if mudlogging equipment is used then reporters must use Calculation Method 1 and this approach is adopted in the final rule. In response to a comment that is addressed later in the preamble, we are providing additional clarity in the final rule with respect to applicability of Calculation Method 1. The final rule adds that Calculation Method 1 is required when reporters have taken mudlogging measurements, including mud pumping rate and gas trap-derived gas concentration that is reported in parts per million (ppm) or is reported in units from which ppm can be derived. Consistent with the proposal, the final rule requires the reporter to use emission factors if mudlogging measurements are not taken.
                    </P>
                    <P>
                        The EPA also disagrees with the commenter that mudlogging measurements are not representative of the drilling cycle because they may only be taken at the early stages of drilling. Proposed equation W-41 used the average mud rate for the representative 
                        <PRTPAGE P="42096"/>
                        well, r, in gallons per minute, rather than a single point measurement to determine methane emissions from mud degassing. In considering this comment, however, the EPA determined that the definition of the term X
                        <E T="52">n</E>
                         in equation W-41 should be the “average” gas concentration in the drilling mud as measured by the gas trap, in parts per million (adding “average” to the proposed term in the final equation). The final provisions to use the average gas concentration should ensure consistency with the use of the average mud rate (MR
                        <E T="52">r</E>
                        ), resulting in emissions calculations that are based on average measurements that allow for fluctuations in concentrations and flows inherent in field operations.
                    </P>
                    <P>The EPA disagrees with the commenter's suggestion that all reporters be allowed to use Calculation Method 2 regardless of whether mudlogging was performed for at least one well. Consistent with CAA section 136(h), the overall intent of this rulemaking is for reporting to be based on empirical data and have greater accuracy of total emissions data from facilities. Therefore, the final provisions include a modification from proposal to require that reporters use Calculation Method 1 if they take mudlogging measurements for the entire time period from the penetration of the first hydrocarbon bearing zone until drilling mud ceases to be circulated in the wellbore. This requirement applies only if the mudlogging measurements provide a gas concentration in ppm or in units from which ppm can be derived. If a reporter does not use mudlogging, then reporters must use the emission factors in Calculation Method 2. After considering this comment, the EPA is finalizing a third method that requires operators to use a combination of the two methodologies when a varying level of directly measured data is available. For example, where mudlogging was only used at certain intervals during drilling an individual well, the third method would apply and the reporter would use Calculation Method 1 during those intervals while applying Calculation Method 2 to the other drilling periods. The EPA is finalizing this hybrid method as a new Calculation Method 3 in 40 CFR 98.233(dd)(3), that requires use of Calculation Method 1 when mudlogging measurements are available and use of Calculation Method 2 for the remaining period of drilling activity where mudlogging data is not available.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters requested that the EPA clarify that the total time that drilling mud is circulated in the representative well in Calculation Method 1 should be calculated based on circulating time in the hydrocarbon bearing zones only (
                        <E T="03">i.e.,</E>
                         excluding surface holes drilled by a spudder rig when no hydrocarbons are present).
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA agrees that the final definition of T
                        <E T="52">r</E>
                         and T
                        <E T="52">p</E>
                         in Calculation Method 1, “Total time that drilling mud is circulated in the representative well in minutes,” should be amended from proposal to reflect that time of mud circulation in equations W-41, W-42, and W-43 does not begin until the first hydrocarbon-bearing zone is penetrated by the well bore. This change is consistent with the first day of drilling days, DD
                        <E T="52">p</E>
                        , in Calculation Method 2, which is the first day that the borehole penetrated the first hydrocarbon-bearing zone. The final rule reflects these changes from proposal to Calculation Method 1.
                    </P>
                    <P>The EPA disagrees with the suggestion to clarify that “total time that drilling mud is circulated in the representative well” should be calculated based on circulating time in the hydrocarbon bearing zones only. Hydrocarbons can still become entrained in drilling mud even after the well bore moves out of the hydrocarbon-bearing zone. The use of an average mud rate and average natural gas concentration combined with the change from proposal just described, to only consider the start of mud circulation to be the time when the first hydrocarbon zone is penetrated, should appropriately address the commenter's concerns.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters stated that a further complication of the proposed method for quantifying methane emissions from drilling mud degassing is that the concentration of natural gas (or methane) in drilling mud is not currently specifically measured and is difficult to obtain. Further, commenters stated it is not measured by mud loggers in units of ppm, as the measurement instrument used is in units that are not representative of methane concentration.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA acknowledges that some mudlogging equipment may use units that are not convertible to ppm. Therefore, we have further qualified the use of Calculation Method 1 to be required if you have taken mudlogging measurements from the penetration of the first hydrocarbon bearing zone until drilling mud ceases to be circulated in the wellbore, including mud pumping rate and gas trap-derived gas concentration that is reported in parts per million (ppm) or is reported in units from which ppm can be derived. We further note that reporters must use Calculation Methodology 2 emission factors if they do not take mud logging measurements as described above. The EPA disagrees that the concentration of natural gas in drilling mud is not specifically measured and is difficult to obtain. Mudlogging equipment capable of measuring gas concentration and in ppm is available. Even when other available mudlogging equipment does not produce data in these units, the mudlogging equipment may use specific units based on their sensors and calibration that are convertible to percent or ppm. Therefore, the final rule retains the requirement to use these measurements when available under Calculation Method 1 or Calculation Method 3.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters expressed concern that the proposed emission factors in Calculation Method 2 are dated and based on offshore wells. Commenters suggested that the EPA instead adopt emission factors for drilling mud degassing in the American Petroleum Institute's (API) Compendium.
                        <SU>33</SU>
                        <FTREF/>
                         Commenters also expressed concern that the proposed rule did not allow for adjustments to emission factors in Calculation Method 2 based on local conditions. Commenters noted that mud weight is critical in controlling formation pressure and the flow of hydrocarbons into the well bore during the drilling process and the various methods do not account for this. A commenter also suggested that the emission factors should be derived as a function of well dimensions to better represent mud degassing emissions. The commenter stated that, otherwise, proposed Calculation Methodology 2 should be revised based on drilling time in the hydrocarbon hole section, and not overall event days. The commenter stated that there can be multiple days in a hydrocarbon hole section where the pumps are not circulating.
                    </P>
                    <FTNT>
                        <P>
                            <SU>33</SU>
                             
                            <E T="03">Compendium of Greenhouse Gas Emissions Methodologies For The Natural Gas And Oil Industry.</E>
                             Produced by URS Corporation for American Petroleum Institute. November 2021. Available at 
                            <E T="03">https://www.api.org/-/media/files/policy/esg/ghg/2021-api-ghg-compendium-110921.pdf.</E>
                             Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        Finally, a commenter noted that the EPA proposes to define the number of drilling days differently than the CenSARA study. The commenter stated that rather than considering the first drilling day to be the day the well is spudded, the EPA proposed that the total number of drilling days is the sum of all days from the first day that the borehole penetrates the first 
                        <PRTPAGE P="42097"/>
                        hydrocarbon-bearing zone through the completion of all drilling activity.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         In proposing emission factors for drilling mud degassing, the EPA considered the sources available with published emission factors. As the commenter notes, API does include emission factors in Section 6.2.1 of its Compendium of Greenhouse Gas Emission Methodologies for the Natural Gas Industry. The API emission factors are lower than those included in the CenSARA guidelines; however, the factors are based on API member comments on a letter from API submitted to the EPA in 2020 with respect to mud degassing emission factors being considered for the U.S. Inventory of Greenhouse Gas Emissions. See Section 6.2.1 of the API Compendium. The commenter has not submitted documentation to support the recommended emission factors other than reference to the API Compendium based on API member comments. This does not allow the EPA to further investigate the derivation of the API emission factors. In contrast, the basis for emission factors used in the CenSARA and NYSERDA guidelines is a 1977 study by the EPA's Office of Air Quality Planning and Standards, which derived emission factor based on engineering equations. The methodology is public and has been subject to review. We acknowledge that the factors are based on offshore operations; however, we believe they present a reasonable approximation of onshore emissions. We note that the final rule provides reporters with the option to take site-specific measurements and use measured data if they do not believe the emission factors, adjusted for local conditions, accurately represent emissions from mud degassing from their wells. Therefore, our assessment of the available information is that the proposed emission factors (from the published CenSARA study) are appropriate and we are including them in the final provisions.
                    </P>
                    <P>
                        For Calculation Method 2, the EPA generally agrees with the commenter that adjustment for local conditions may more accurately reflect emissions at the facility than reliance solely on nationwide emission factors. The CenSARA guidelines allow for local adjustment of CH
                        <E T="52">4</E>
                         emissions by applying the ratio of the measured CH
                        <E T="52">4</E>
                         mole fraction to the mole fraction used to develop the emission factor, 83.85,
                        <SU>34</SU>
                        <FTREF/>
                         although the guidelines do not specify how the measurement is derived. The EPA believes allowing for adjustment to local conditions is a reasonable approach when using an emission factor and is finalizing the rule with such an adjustment from proposal to Calculation Method 2. Specifically, we are adding two data inputs to equation W-44. The first is X
                        <E T="52">CH4</E>
                        , which is the CH
                        <E T="52">4</E>
                         mole fraction in the sub-basin. The CH
                        <E T="52">4</E>
                         mole fraction used in equation W-44 will be the mole fraction for the sub-basin as reported for the onshore production facility in 40 CFR 98.236(aa)(ii) because, for a reporter using Calculation Method 2, the reporter has not taken mudlogging measurements including gas concentration. The second data input is the nationwide CH
                        <E T="52">4</E>
                         mole fraction of 83.85. Reporters using Calculation Method 2 will multiply the number of drilling days by the appropriate emission factor as defined in equation W-44. That value will then be multiplied by the ratio of X
                        <E T="52">CH4</E>
                         to 83.35 to derive emissions from mud degassing.
                    </P>
                    <FTNT>
                        <P>
                            <SU>34</SU>
                             See page 86 of 2011 
                            <E T="03">Oil and Gas Emission Inventory Enhancement Project for CenSARA States.</E>
                             Produced by ENVIRON International Corporation for Central States Air Resources Agencies. November 2011. Available at 
                            <E T="03">https://www.deq.ok.gov/wp-content/uploads/air-division/EI_OG_Final_Report_CenSara_122712.pdf</E>
                             and in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>The EPA disagrees with the commenters that mud weight should be considered in the emission factors in Calculation Method 2 and in Calculation Method 1. Calculation Method 1 effectively takes mud weight into account because it uses direct measurement. For example, if mud weight is high, or overbalanced, the amount of gas entering the mud stream is reduced and the average gas concentration will decrease. If mud weight is low, or underbalanced, the gas concentration in the drilling mud will increase. For Calculation Methodology 2, none of the available methodologies identify the mud weight used to determine the emission factors; therefore, it is not possible to modify the emission factors by applying a specific mud weight to the emission factor. Separate emission factors for water-based, oil-based and synthetic drilling muds should address the commenters' concern.</P>
                    <P>
                        The EPA does not agree with the commenter's suggestion for Calculation Method 2 to consider well dimensions to better represent mud degassing emissions. Well dimensions alone do not determine the quantity of emissions that may result from mud degassing. Use of separate emission factors for water-based, oil-based and synthetic muds and allowing use of site-specific CH
                        <E T="52">4</E>
                         mole fractions provide flexibility to develop more site-specific emissions for mud degassing using Calculation Method 2. However, the EPA does agree with the commenter that the definition of drilling days, DD
                        <E T="52">p</E>
                        , in equation W-44 should be revised to reflect the actual number of days drilling mud is circulated in the wellbore. This change is consistent with how the EPA defines the last drilling day, which is the day drilling mud ceases to be circulated in the wellbore. Entrainment of gas in drilling mud and resulting emissions are unlikely if mud is not circulating. There are many reasons why an operator may stop mud pumping on a well site including mechanical reasons, well workovers, health and safety issues, and other reasons.
                    </P>
                    <P>
                        With respect to the number of drilling days in Calculation Method 2 and the comment that the EPA had changed the start of drilling days from CenSARA definition (which is the date the well is spudded), the EPA proposal intended to add clarity to Calculation Method 2 by proposing the first drilling day as the day that the borehole penetrated the first hydrocarbon-bearing zone and the last drilling day is the day drilling mud ceases to be circulated in the wellbore. The objective of the proposal was to more accurately calculate emissions using Calculation Method 2 by limiting the number of days multiplied by the emission factor to the days when mud is actually circulating in hydrocarbon-bearing zones when the potential for gas entrainment exists. If spudding is the standard for determination of the first day, this may add days to the emissions calculation when CH
                        <E T="52">4</E>
                         is not actually entrained in the mud. Likewise, including days when the drill bore is retreating and mud is no longer circulating would include additional days in Calculation Method 2 when there is no potential for CH
                        <E T="52">4</E>
                         to become entrained in the mud. Together these assumptions would overestimate emissions. Therefore, we are finalizing the definition of “total number of drilling days” as proposed except for the change that drilling days are further defined as the days when drilling mud is circulated in the wellbore.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Several commenters indicated that wells subject to reporting under this source are often wildcat or delineation wells, and, as such, should be subject to confidentiality or a delay in reporting.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         After further review, we agree with the commenters that many wells where drilling mud is used are exploratory wildcat or delineation wells. After consideration of this comment, we are finalizing the reporting requirements for Calculation Method 1 to provide a 2-year delay in 
                        <PRTPAGE P="42098"/>
                        reporting certain data elements for all wells reported using Calculation Method 1 if the well is a wildcat or delineation well. Specifically, the Average concentration of natural gas in the drilling mud (X
                        <E T="52">n</E>
                         in equation W-41), in parts per million, the Measured mole fraction for CH
                        <E T="52">4</E>
                         in natural gas entrained in the drilling mud (GHG
                        <E T="52">CH4</E>
                         in equation W-41), and the Total time that drilling mud is circulated in the well (T
                        <E T="52">r</E>
                         in equations W-41 and W-42 and Tp in equation W-43) are eligible for the 2-year delay for any well that is a wildcat and/or delineation well. In addition, the following data elements are eligible for the 2-year delay when one or more wells to which the calculated CH
                        <E T="52">4</E>
                         emissions rate for the representative well (ER
                        <E T="52">s,CH4,r</E>
                         in equation W-42) is applied is a wildcat and/or delineation well: the Average mud rate (MR
                        <E T="52">r</E>
                        ) and the Calculated CH
                        <E T="52">4</E>
                         emissions rate (ER
                        <E T="52">sCH4,r</E>
                        ). Reporting of the Total time that drilling mud is circulated in the well (Tr in equations W-41 and W-42) for the representative well may also be delayed for 2 years if one or more wells to which the calculated CH
                        <E T="52">4</E>
                         emissions rate for the representative well (ER
                        <E T="52">s,CH4,r</E>
                         in equation W-42) is applied is a wildcat and/or delineation well. Wildcat and delineation wells are considered exploratory wells in the oil and gas industry, and data on these wells are generally considered sensitive information by the industry. State oil and gas commissions commonly hold such data from public release for two years. Therefore, the EPA has determined that these inputs to emission equations should be directly reported but are subject to a 2-year delay for exploratory wells to acknowledge the sensitive nature of the data and to ensure that the data cannot be back calculated prior to the end of the 2-year delay. However, we emphasize that this information would be considered to be emission data under CAA section 114 that is not eligible for confidential treatment upon submission to the agency, and thus will be made available to the public upon submission. Furthermore, emissions from any well with well degassing must still be reported annually and we further note that we have other information that will allow verification of reported emissions. Moreover, the EPA intends to be diligent in reviewing and reconciling delayed data with reported emissions data, and we also stress that, although the delayed data may not be reported in the initial reporting year, reporters must maintain records supporting their emission calculations and these records are subject to review by the EPA. Finally, the EPA intends to further evaluate whether this information will be required and, if so, may require reporting without delay in a future rulemaking.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Several commenters did not support the proposed requirement in 40 CFR 98.236(dd) to report certain data elements when using Calculation Method 1 to calculate emissions from mud degassing. Specifically, the commenters disagreed with reporting total vertical depth of the well and the circulation time of the drilling mud within the wellbore stating that the EPA did not address why the information would be requested. They further noted that in the case of total vertical depth, the reported data would not provide representative information for horizontal wells and would not improve the reported data quality.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA disagrees with the commenter that total vertical depth and mud circulation time should not be reported for Calculation Method 1 in 40 CFR 98.236(dd). Although formations dip and well to well correlations are sometimes subject to discontinuities, total vertical depth combined with identification of the stratigraphic formation provides a reasonable assurance that wells are drilled into the same hydrocarbon producing formations. Consistent with the change in Calculation Method 1 to apply the emissions rate from the representative well to other wells in the same sub-basin drilling in the same stratigraphic interval versus the same approximate depth, the EPA has added a reporting requirement to 40 CFR 98.236(dd) in the final rule to require reporters using Calculation Method 1 to also report the target hydrocarbon-bearing stratigraphic formation to which the well is drilled in addition to the total vertical depth. In response to the commenters' concerns about the requirement to report the total time that drilling mud is circulated in the well, this data element is necessary for the EPA to verify the reported CH
                        <E T="52">4</E>
                         emissions using Calculation Method 1. Based on consideration of public comment and further research, however, we are finalizing that total time drilling mud is circulated in the well and other data elements in Calculation Method 1 are eligible for a 2-year delay for wildcat and delineation wells. See the response to the comment above for additional information.
                    </P>
                    <HD SOURCE="HD3">5. Crankcase Venting</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>The EPA is finalizing with revisions from proposal, as discussed further in this section, the addition of crankcase venting as a new emission source to be reported under 40 CFR 98.236(ee) by facilities in the Onshore Petroleum and Natural Gas Production, Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, LNG Storage, LNG Import and Export Equipment, Natural Gas Distribution, and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments. The EPA is finalizing with revisions from proposal, as discussed further in this section, methodologies for calculating emissions from crankcase venting under 40 CFR 98.233(ee). We are also finalizing as proposed revisions to 40 CFR 98.232 to include crankcase venting reporting requirements for the appropriate industry segments.</P>
                    <P>The EPA is finalizing with revisions from proposal the definition of crankcase venting under 40 CFR 98.238, with a clarification that an ingestive system may include, but is not limited to, closed crankcase ventilation systems and closed breather systems. We also are specifying in the revised definition that crankcase venting does not include vents where emissions are routed to another closed vent system, since these emissions are not released to the atmosphere. Further, following consideration of comments received, we are stating in the introductory paragraph of 40 CFR 98.233(ee) that crankcase venting emissions must only be calculated and reported for RICE with a rated heat capacity greater than 1 million British thermal units per hour (MMBtu/hr) (or the equivalent of 130 horsepower), which is consistent with the RICE combustion emissions reporting threshold under 40 CFR 98.236(z). We are also making revisions from proposal, after consideration of comments, to 40 CFR 98.233(ee) and 40 CFR 98.236(ee) to remove gas turbines from the final source types subject to crankcase venting emissions reporting.</P>
                    <P>
                        Regarding revisions from proposal to the final methodologies for calculating emissions from crankcase venting under 40 CFR 98.233(ee), following consideration of comments received and consistent with section II.B. of this preamble, we are adding a direct measurement option for crankcase venting emissions as Calculation Method 1. Specifically, we are splitting the proposed 40 CFR 98.233(ee) into two paragraphs, with 40 CFR 98.233(ee)(1) for the added direct measurement option (final Calculation Method 1) and 40 CFR 98.233(ee)(2) for the final emission factor method (final Calculation Method 2, which we proposed under 40 CFR 98.233(ee), 
                        <PRTPAGE P="42099"/>
                        equation W-45) with modifications from proposal.
                    </P>
                    <P>
                        For the final Calculation Method 1 in 40 CFR 98.233(ee)(1), we are allowing the use of screening methods in 40 CFR 98.234(a) to determine whether quantitative emissions measurements are needed, similar to the rod packing methodologies for reciprocating compressors under 40 CFR 98.233(p). If emissions are detected using the screening methods, which for purposes of this calculation method are considered detected whenever a leak is detected according to the screening method used, direct measurement must be used to determine CH
                        <E T="52">4</E>
                         emissions using the following technologies for conducting direct measurement of crankcase vent emissions: high volume samplers, meters (such as rotameters, turbine meters, hot wire anemometers, and others), or calibrated bags, in accordance with the methods in 40 CFR 98.234(b) through (d). If no emissions are detected during screening, then the reporter may assume that the volumetric emissions from the crankcase vent are zero. If a reporter elects to conduct screening and direct measurement of crankcase vents, all operating engines at the time of screening must then be screened at the facility, well-pad site, or gathering and boosting site at least once annually. Under the final Calculation Method 1, the reporter must then use equation W-45 under 40 CFR 98.233(ee)(1)(iv) to calculate the annual volumetric CH
                        <E T="52">4</E>
                         emissions calculation for each RICE that was measured during the reporting year. We are also adding clarification to the final rule for reporters with crankcase vents tied into a manifolded group under 40 CFR 98.233(ee)(1)(iii). Under the final provisions for Calculation Method 1, if the manifolded group contains only crankcase vent sources, reporters must divide the measured volumetric flow equally between all operating RICE. Additionally, under the final provisions for this methodology, if the manifolded group contains crankcase vent sources and compressor vent sources, we assume that emissions are being characterized under 40 CFR 98.233(o) or (p) and should be reported under 40 CFR 98.236 (o) or (p), as applicable. We are also adding under 40 CFR 98.236(ee)(2) several reporting requirements for crankcase vent emissions calculated through direct measurement under 40 CFR 98.233(ee)(1), as well as a reporting requirement under 40 CFR 98.236(ee)(1)(v) for the count of reciprocating internal combustion engines with crankcase vents that were in a manifolded group containing a compressor vent source with emissions reported under 40 CFR 98.236(o) or (p).
                    </P>
                    <P>
                        We are also adding language in the final rule to instruct reporters who use Calculation Method 1 for calculating volumetric CH
                        <E T="52">4</E>
                         emissions to use the procedures in 40 CFR 98.233(v) to calculate mass CH
                        <E T="52">4</E>
                         emissions. This is standard language in all paragraphs of 40 CFR 98.233 for emission sources that require volumetric emission calculations. We are adding this language for consistency with the mass reporting requirements being finalized in 40 CFR 98.236(ee)(2)(ii).
                    </P>
                    <P>For the final Calculation Method 2 in 40 CFR 98.233(ee)(2), including final equation W-46, this method provides a component-level average emission factor approach for estimating emissions for crankcase ventilation based on the number of RICE in the facility. The final provision have been modified from proposal to specify that this emission calculation should be performed for each RICE with a crankcase vent that is either not operating at the time of the direct emissions measurement conducted under 40 CFR 98.233(ee)(1), or at a facility, well-pad site, or gathering and boosting site where the reporter elects not to conduct direct emissions measurement on any engines. Correspondingly, this method is being modified from proposal to be performed per RICE. For example, where a reporter is using Calculation Method 2 for RICE with crankcase vents that are manifolded with other vents or equipment, equation W-46 should be performed for each RICE with a crankcase vent that is part of the manifold. As equation W-46 will be performed for each RICE, we are changing from proposal the requirement to report average estimated time that the RICE with crankcase venting were operational in the calendar year to instead require total time that each applicable RICE was operational during the calendar year. We are also changing from proposal the requirement to report the number of crankcase vents at the well-pad site, gathering and boosting site, or facility, to instead require reporting of the number of RICE with crankcase vents that operated at some point in the calendar year.</P>
                    <P>
                        After consideration of comments received, the emission factor provided as part of final equation W-46 is being changed from units of standard cubic feet whole gas per hour per source to units of kilograms CH
                        <E T="52">4</E>
                         per hour per source. We are also revising equation W-46 from proposal to include the unit conversion from kilograms CH
                        <E T="52">4</E>
                         to metric tons CH
                        <E T="52">4</E>
                         for consistency with the emissions reporting requirements of subpart W.
                    </P>
                    <P>
                        We are also adding language in the introductory paragraph of 40 CFR 98.233(ee) for the final rule that for reporters with crankcase vents routed to flares, the CO
                        <E T="52">2</E>
                        , CH
                        <E T="52">4</E>
                         and N
                        <E T="52">2</E>
                        O emissions that result from combustion of the crankcase vent stream are reported as flare stack emissions under 40 CFR 98.236(n). The EPA is specifying that crankcase vents routed to a flare would follow the calculation requirements in 40 CFR 98.233(n) and would report flared crankcase emissions (CO
                        <E T="52">2</E>
                        , CH
                        <E T="52">4</E>
                        , and N
                        <E T="52">2</E>
                        O) separately from vented crankcase emissions (CH
                        <E T="52">4</E>
                        ). We are finalizing requirements that flared emissions from crankcase vents are not required to be calculated and reported separately from other flared emissions. Instead, emission streams from crankcase vents that are routed to flares are required to be included in the calculation of total emissions from the flare according to the procedures in 40 CFR 98.233(n) and reported as part of the total flare stack emissions according to the procedures in 40 CFR 98.236(n), in the same manner as emission streams from other source types that are routed to the flare. See section III.N. of this preamble for more information on the final flaring calculation and reporting provisions.
                    </P>
                    <P>We are also finalizing requirements in 40 CFR 98.236(ee)(1) to report the total number of RICE with crankcase vents at the site (regardless of vent disposition), the number of these RICE that operated and were vented to the atmosphere for at least a portion of the year, and the number of these RICEs that operated and were routed to a flare for at least a portion of the year. We added a sentence at 40 CFR 98.233(ee) to further clarify these reporting requirements apply even when emissions from the crankcase vents are required to be reported under other sources (flares).</P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to add crankcase venting as an emission source for Onshore Petroleum and Natural Gas Production, Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, LNG Storage, LNG Import and Export Equipment, Natural Gas Distribution, and Onshore Petroleum and Natural Gas Gathering and Boosting facilities.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Many commenters noted that natural gas turbines do not have crankcase vents, or an equivalent 
                        <PRTPAGE P="42100"/>
                        emission source, and thus should be excluded from the crankcase venting emission source.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA agrees with the commenters that there was an inadvertent error in including natural gas turbines in the crankcase venting emission source category. We are finalizing a correction that will remove references to natural gas turbines from 40 CFR 98.233(ee) and 40 CFR 98.236(ee).
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Several commenters requested the addition of a direct measurement option for crankcase vent methane emissions. The commenters stated that the IRA directs the EPA to include improved subpart W emission estimates by using empirical data, which they asserted is not addressed in the proposed crankcase venting. Commenters provided several different suggestions on how to incorporate direct measurement into the crankcase venting emission source.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We agree with the commenters that a direct measurement option for the crankcase venting emission source could be appropriate and consistent with the directives of CAA section 136 if an appropriate direct measurement option could be identified. The EPA has considered all measurement options suggested by commenters, which included mimicking the measurement requirements of reciprocating and centrifugal compressors, allowing for site-specific emission factors, and/or allowing for emissions screening. At this time, we have determined that, consistent with the provisions for reciprocating compressor rod packing, a multi-step method for a direct measurement option is appropriate. Reporters may elect to complete emissions screening and then, if emissions from the crankcase vent are detected during screening, a measurement must be taken. If the reporter elects not to complete emissions screening, then all crankcase vents must be directly measured from engines operating at the time of the measurement event. Direct measurements must be taken at least annually on operating engines. We have also determined that at this time the most appropriate direct measurement methodologies for the crankcase venting emission source are provided in 40 CFR 98.234(b) through (d), which allow the use of an appropriate meter, calibrated bag, or high volume sampler. Regarding screening methods, we have determined that at this time any of the methods provided in 40 CFR 98.234(a) are appropriate for screening except for the acoustic leak detection method in 40 CFR 98.234(a)(5). The acoustic leak detection method is applicable only for through-valve leakage so it is not applicable to the crankcase vent. We have included this optional first step screening as an appropriate approach to reduce burden on those reporters with a significant quantity of crankcase vents while maintaining accuracy in total emissions. The EPA is not at this time allowing the option for reporters to develop site-specific emission factors because this methodology would require the specification of a minimum number of measurements that must be taken to be representative and new restrictions around these measurements, which should be proposed to allow comments.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Some commenters requested additional clarification on the definition of crankcase venting. Specifically, commenters requested that the EPA update the definition to clarify the term “ingestive system,” as it is more commonly referred to as a closed crankcase ventilation system or a closed breather system. Further, one commenter noted that as the EPA excludes crankcase vents that are returned to the combustion process from the crankcase venting definition, the EPA should consistently exclude crankcase vents that are routed to another closed vent system, as this would provide operators more flexibility.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA agrees with the commenters and has clarified the definition of crankcase venting in 40 CFR 98.238 of the final rule that an ingestive system may include, but is not limited to, closed crankcase ventilation systems and closed breather systems. Additionally, the EPA agrees that routing crankcase vent emissions to any closed vent system should allow the RICE to be excluded from reporting crankcase vent emissions and has therefore clarified this exemption in the crankcase venting definition.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Some commenters requested the ability to account for emission controls on crankcase vents. Commenters recommend adding this flexibility, which they state also has the added impact of incentivizing controls where feasible.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA agrees that reporters should be able to account for emission controls on crankcase vents. In the final rule, the EPA has added to the introductory paragraph of 40 CFR 98.233(ee) that flared emissions from crankcase vents should be calculated and reported according to 40 CFR 98.233(n) and 40 CFR 98.236(n), respectively. As stated above, the EPA has also excluded crankcase vents that route emissions to another closed vent system, such as a vapor recovery system, from the definition of crankcase venting. Also as noted above, the EPA has added a measurement option that will allow reporters to account for other emission controls on crankcase vents.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Several commenters noted that the parameter GHG
                        <E T="52">CH4</E>
                         in proposed equation W-45 incorrectly requires reporters to assume that the methane content of the crankcase vent stream is equivalent the methane content of the gas stream entering the RICE. They state that the crankcase vent stream can be diluted and may have a much lower methane content than the methane content of gas stream entering the RICE or the default value referenced. Commenters requested the ability to either measure the methane content of the crankcase gas vent, apply a scaling factor to the CH
                        <E T="52">4</E>
                         content of the inlet gas, or use best available data to determine the GHG
                        <E T="52">CH4</E>
                         parameter.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We agree that the use of the methane content in the gas stream entering the RICE would produce a conservative estimate of methane emissions from the crankcase vent. The emission factor upon which the proposed whole gas emission factor was based was in terms of THC but it is much more direct to convert this THC emission factor to methane. Thus, we are changing the emission factor proposed for Calculation Method 2, which was in terms of standard cubic feet of whole gas per hour, to use terms of kilograms CH
                        <E T="52">4</E>
                         per hour. To do this, we reviewed the source of the proposed crankcase emission factor, the 2021 API Compendium.
                        <SU>35</SU>
                        <FTREF/>
                         API's emission factor, 2.28 standard cubic feet per hour per source, was developed from results from Phase II of a comprehensive measurement program conducted to determine cost-effective directed inspection and maintenance (DI&amp;M) control opportunities for reducing natural gas losses due to fugitive equipment leaks and avoidable process inefficiencies. Phase II of the program was conducted at five gas processing plants, seven gathering compressor stations, and twelve well sites during 2004 and 2005.
                        <SU>36</SU>
                        <FTREF/>
                         This study, “EPA 
                        <PRTPAGE P="42101"/>
                        Phase II Aggregate Site Report: Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites, Technical Report,” prepared by National Gas Machinery Laboratory, Clearstone Engineering, Ltd., and Innovative Environmental Solutions, Inc. (hereafter referred to as the “Clearstone Phase II Study”), provided the crankcase emission factor as 0.12 kilograms of THC per hour per source, which API then converted to a whole gas factor.
                    </P>
                    <FTNT>
                        <P>
                            <SU>35</SU>
                             
                            <E T="03">Compendium of Greenhouse Gas Emissions Methodologies For The Natural Gas And Oil Industry.</E>
                             Produced by URS Corporation for American Petroleum Institute. November 2021. Available at 
                            <E T="03">https://www.api.org/-/media/files/policy/esg/ghg/2021-api-ghg-compendium-110921.pdf</E>
                             and in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>36</SU>
                             
                            <E T="03">Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites.</E>
                             EPA Phase II Aggregate Site Report prepared for U.S. EPA Natural Gas STAR Program by Natural Gas Machinery Laboratory, Clearstone Engineering Ltd., 
                            <PRTPAGE/>
                            and Innovative Environmental Solutions, Inc. March 2006. Available at 
                            <E T="03">https://www.epa.gov/sites/default/files/2016-08/documents/clearstone_ii_03_2006.pdf</E>
                             and in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        In order to provide an emission factor in terms of kilograms of CH
                        <E T="52">4</E>
                         per hour per source for use in the equation W-46, the EPA started with the Clearstone Phase II study's THC emission factor. We expect the THC in the crankcase vent originates from either direct natural gas leaks into the crankcase or uncombusted hydrocarbons in exhaust gas that leaks into the crankcase. In either event, we expect the ratio of methane to THC in the crankcase vent to be represented by the average ratio of methane to THC in the natural gas used as fuel for the engine. We used the average methane-to-total organic compounds (TOC) weight ratios for production of 0.695 and transmission of 0.908 used in estimating emission impacts for the NSPS OOOOb rule (see Docket ID. No. EPA-HQ-OAR-2021-0317-1578, attachments 4 through 6, tab “Composition and Factors”). Using these factors, the EPA converted the Clearstone Phase II study THC emission factor from units of kilograms THC per hour per source to units of kilograms CH
                        <E T="52">4</E>
                         per hour per source.
                        <SU>37</SU>
                        <FTREF/>
                         The emission factors provided in equation W-46 of the final rule are 0.083 kg CH
                        <E T="52">4</E>
                        /hr/engine for onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities and 0.11 kg CH
                        <E T="52">4</E>
                        /hr/engine for all other applicable industry segments. We are also revising equation W-46 to include the unit conversion from kilograms CH
                        <E T="52">4</E>
                         to mt CH
                        <E T="52">4</E>
                         for consistency with the emissions reporting requirements of subpart W.
                    </P>
                    <FTNT>
                        <P>
                            <SU>37</SU>
                             0.694769294934942 kg CH
                            <E T="52">4</E>
                            /kg TOC for production facilities; 0.907710347197016 kg CH
                            <E T="52">4</E>
                            /kg TOC for transmission facilities. It was assumed that TOC = THC for the purposes of this conversion and that all THC in the crankcase gas is from uncombusted fuel gas.
                        </P>
                    </FTNT>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter was concerned that engine size was not considered in calculating emissions or developing the emission factor used in proposed equation W-45. The commenter states that gas storage compressors and compressor station engines on which the proposed emission factor is based are of a much larger scale than production facility engines and are therefore expected to have a much higher vent rate. The commenter requested a de-minimis exemption for very small engines, or the allowance of direct measurement of crankcase vents.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA is finalizing the option for direct measurement of crankcase gas vent emissions, as previously discussed. In an effort to be consistent with the provisions of 40 CFR 98.233(z), the EPA is changing the language in the introductory paragraph of 40 CFR 98.233(ee) to state that only RICE with a rated heat capacity greater than 1 MMBtu/hr (or the equivalent of 130 horsepower) must calculate emissions from crankcase venting. We may consider evaluating the removal of this exclusion in future rulemakings.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Several commenters opposed the emission factor methodology, which was proposed on a per vent approach. Commenters requested that the emission factor be per RICE, rather than per crankcase vent, to avoid confusion. One commenter also noted that the proposed emission factor of 2.28 scfh per vent is not consistent with crankcase emissions per engine based on the study, “Characterization of Crankcase Ventilation Gas on Stationary Natural Gas Engines,” by Colorado State University (March 2023). One commenter further stated that the reporting requirements under 40 CFR 98.236(ee) should be on a per-site basis.
                    </P>
                    <P>Additionally, some commenters requested clarification on the term “vent” in proposed equation W-45. Commenters noted that vents can be manifolded together. Commenters stated that, for example, when installed within a structure, crankcase vents from multiple engines are typically routed to a central manifold and exhausts to the exterior of the structure through a single “vent.” The commenters stated that the proposed rule could be interpreted as allowing the 2.28 scfh per vent emission factor to apply to the manifolded vent rather than each individual engine's vent.</P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA has reviewed the source of the proposed emission factor, the Clearstone Phase II Study, and confirmed that the emission factor provided in the study is in units of kilograms THC per hour per crankcase vent, but additional detail on the measurement locations and vent configurations is not provided in the study. However, the EPA agrees with the commenters that the methodology would be more clear if the factor was presented on a per RICE basis, especially for crankcase vents that are manifolded together. Based on a technical drawing included in the Clearstone Phase II Study, the EPA assumes that the Clearstone Phase II Study emission factor was likely representative of crankcase vent emissions from the whole engine. Therefore, we have revised the emission factor methodology and equation W-46 to be per RICE in the final rule. Further, we have provided a calculation methodology for reporters who elect to directly measure emissions from a manifolded vent; under the final provisions for this methodology, if the manifolded group contains only crankcase vent sources, reporters must divide the measured volumetric flow equally between all operating RICE. Additionally, under the final provisions for this methodology, if the manifolded group contains crankcase vent sources and compressor vent sources, the measurement made when the compressor is in operating mode must be included in the emissions being characterized under 40 CFR 98.233(o) or (p) and must be reported under 40 CFR 98.236 (o) or (p), as applicable. Therefore, we are not requiring facilities that manifold their crankcase vent with compressor vent sources to separately characterize their crankcase vent emissions, because that would double-count these emissions. This approach is consistent with the goal of CAA section 136(h) to develop accurate facility-wide methane emissions.
                    </P>
                    <P>
                        Further, the EPA has reviewed the study, “Characterization of Crankcase Ventilation Gas on Stationary Natural Gas Engines,” by Colorado State University (March 2023) (hereafter referred to as the “2023 CSU Study”) and determined that the data is not appropriate for use in the final rule. We have determined that the 2023 CSU study is too limited to establish national average CH
                        <E T="52">4</E>
                         concentration values. The study team studied one four-stroke lean-burn engine in the field and lab-tested two additional engines (one four-stroke rich-burn and one two-stroke lean-burn). The field-tested engine was at tested at 85 percent load, while the lab-tested engines were measured at several different loads. The study sampled and characterized the crankcase gas on the natural gas engines with the end goal of installing a closed crankcase recirculation/filtration system. The field testing on the four-stroke lean-burn engine found that CH
                        <E T="52">4</E>
                         accounts for 3.6 
                        <PRTPAGE P="42102"/>
                        percent of the crankcase gas. The lab testing on the four-stroke rich-burn engine found higher levels of CH
                        <E T="52">4</E>
                         in the crankcase gas at 5.5 percent by volume, and the two-stroke lean-burn engine had very low levels of CH
                        <E T="52">4</E>
                         in the crankcase gas (0.3 percent by volume). However, the study did not determine a CH
                        <E T="52">4</E>
                         emission rate. Additionally, the 2023 CSU study only tested CH
                        <E T="52">4</E>
                         concentrations in the crankcase gas for three engines, two of which were in controlled conditions of a laboratory setting. The EPA has determined that the results of this study are not representative of the industry as a whole due to the low sample size.
                    </P>
                    <P>In response to the commenter's request to report data for crankcase venting on a per-site basis, the EPA notes that the data reported under 40 CFR 98.236(ee)(2) of the final rule would be aggregated at the facility, well-pad site, or gathering and boosting site level. Given the detailed reporting requirements for facilities electing to use Calculation Method 1, direct measurement data collected under 40 CFR 98.236(ee)(1) of the final rule is required to be reported for each test performed on an operating RICE. However, to alleviate burden, the EPA has revised requirements under 40 CFR 98.236(ee)(2) in the final rule that would remove averaging of data at the site level. In the final rule, we have revised the requirement under 40 CFR 98.236(ee)(2)(iii) from reporting of average operating hours to reporting of total operating hours of RICE with crankcase vents.</P>
                    <HD SOURCE="HD2">D. Reporting for the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting Industry Segments</HD>
                    <HD SOURCE="HD3">1. Summary of Final Amendments</HD>
                    <P>As explained in the 2023 Subpart W proposal, the current sub-basin or basin-level aggregation of data reported within the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting segments can present challenges in the process of emissions verification, with corresponding potential impacts on data quality. The EPA proposed several amendments to reporting requirements within the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments. Consistent with section II.C. of this preamble, the EPA is finalizing these amendments as proposed, with the exception that certain instances of the term “well-pad” have been updated to “well-pad site” in the final amendments. We are finalizing an additional clarifying amendment at 40 CFR 98.236(aa)(10)(v) related to which gathering and boosting sites must be reported and adding a new definition for the term “well-pad site” at 40 CFR 98.238. These clarifying amendments are discussed later in this section. As a first step, the EPA is finalizing as proposed the reporting requirements to be more explicitly consistent with the reporting form structure for the well identification (ID) numbers at the facility as discussed in detail in the 2023 Subpart W Proposal. The EPA is finalizing as proposed revisions to 40 CFR 98.236(aa)(1)(ii) and additional well-specific reporting requirements in 40 CFR 98.236(aa)(1)(iii). Additionally, the EPA is no longer requiring the sub-basin ID to be reported for each well. Instead, reporters will report the sub-basin ID by well-pad and then report the well-pad ID on which the well is located. The well-pad ID is a new data element and is described in the following paragraph. The EPA is also finalizing as proposed the revisions to the requirements to provide a list of well IDs for the five emission source types directly related to wells to instead specify that reporters must report emissions and activity data for each of those emission source types by well within the source-specific reporting requirements, as described later in this section.</P>
                    <P>
                        Second, the EPA is adding as proposed the following data elements: well-pad ID (for Onshore Petroleum and Natural Gas Production segment) and gathering and boosting site ID (for Onshore Petroleum and Natural Gas Gathering and Boosting). These data elements are hereafter collectively referred to as “site-level IDs.” The EPA is adding to 40 CFR 98.236(aa)(1)(iv) (for Onshore Petroleum and Natural Gas Production) and 40 CFR 98.236(aa)(10)(v) (for Onshore Petroleum and Natural Gas Gathering and Boosting) requirements for reporting of information related to each well-pad ID and gathering and boosting site ID, respectively. The reporting elements for each well-pad ID include a unique name or ID for each well-pad, the sub-basin ID, and the location (
                        <E T="03">i.e.,</E>
                         representative latitude and longitude coordinates).
                    </P>
                    <P>To clarify requirements related to the final well-pad ID data element, the EPA is finalizing a definition for the newly defined term well-pad site. The term is defined to mean all equipment on or associated with a single well-pad. Specifically, the well-pad site includes all equipment on a single well-pad plus all equipment associated with that single well-pad. This definition was added to clarify and align the term “well-pad site” with the existing definition of a facility with respect to the Onshore Petroleum and Natural Gas Production industry segment, which is not being updated as part of this rulemaking. The EPA understands that certain equipment at facilities within the Onshore Petroleum and Natural Gas Production segment may not be present directly on a well-pad, such as an off-well-pad tank battery that is associated with a single well-pad. The final definition clarifies that such equipment would be considered part of the well-pad site for emission calculation and reporting purposes. Further discussion of this definition as it applies to specific emission sources can be found in sections III.E.1. (with respect to pneumatic devices) and III.P. (with respect to equipment leaks) of this preamble. Related to this new definition, where the 2023 Subpart W Proposal used the term “well-pad” to describe the level of aggregation for reporting, we are finalizing the associated provisions to instead use the term “well-pad site.”</P>
                    <P>
                        For the Onshore Petroleum and Natural Gas Gathering and Boosting industry segments, the EPA is finalizing requirements as proposed at 40 CFR 98.236(aa)(10)(v) to require reporters to provide a unique name or ID, the site type, and the location for each gathering and boosting site. After consideration of public comment, the EPA is finalizing 40 CFR 98.236(aa)(10)(v) with clarifying language that reporting is only required for gathering and boosting sites for which there were emissions in the calendar year. This is consistent with the intent of the 2023 Subpart W proposed language, as requiring reporting for sites without emissions would not benefit the process of emissions verification or improve data quality and data transparency. For the “site type” for each gathering and boosting site, reporters will select between “gathering compressor station,” “centralized oil production site,” “gathering pipeline site,” or “other fence-line site.” The EPA is finalizing a definition of “gathering compressor station” in 40 CFR 98.238 to be used for the purposes of this reporting requirement and to differentiate gathering compressor stations from other types of compressor stations in subpart W (
                        <E T="03">e.g.</E>
                        , transmission compressor stations). The Onshore Petroleum and Natural Gas Gathering and Boosting industry segment also includes centralized oil production sites 
                        <PRTPAGE P="42103"/>
                        that collect oil from multiple well-pads but that do not have compressors (
                        <E T="03">i.e.,</E>
                         are not “compressor stations”). The EPA is finalizing a definition of a “centralized oil production site” in 40 CFR 98.238 to be used for the purposes of this reporting requirement. For gathering pipelines, the EPA is finalizing a definition of “gathering pipeline site” to specify that it is all the gathering pipelines at the facility within a single state. In previous rulemakings, the EPA has received information from stakeholders noting that there are facility configurations that would not clearly fit within the proposed definition for “gathering compressor station” or “centralized oil production site,” including, but not limited to, booster stations, dehydration facilities, and treating facilities.
                        <SU>38</SU>
                        <FTREF/>
                         The EPA is finalizing as proposed the “other fence-line site” site type to cover these types of sites. For gathering pipelines, the EPA is including within the definition of “gathering and boosting site” that a gathering pipeline site is all the gathering pipelines at the facility within a single state. For the “location” reported for each gathering and boosting site, the EPA is requiring that reporters will provide the representative latitude and longitude coordinates where the site type is a gathering compressor station, centralized oil production site or other fence-line facility, and the state where the site type is a gathering pipeline.
                    </P>
                    <FTNT>
                        <P>
                            <SU>38</SU>
                             Letter from Angie Burckhalter, The Petroleum Alliance of Oklahoma, to Administrator Michael S. Regan, U.S. EPA, Re: Docket ID. No. EPA-HQ-OAR-2019-0424; Revisions and Confidentiality Determinations for Data Elements Under the Greenhouse Gas Reporting Rule. October 6, 2022. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        For the emission source types in the Onshore Petroleum and Natural Gas Production industry segment directly related to wells that currently report by sub-basin (
                        <E T="03">i.e.,</E>
                         well venting for liquids unloading, completions and workovers with hydraulic fracturing, completions and workovers without hydraulic fracturing, and associated gas venting or flaring) or by calculation method and use of a flare (
                        <E T="03">i.e.,</E>
                         well testing), we are finalizing amendments to require reporting of emissions and activity data for each individual well instead of in the prior aggregations (
                        <E T="03">e.g.,</E>
                         by sub-basin). Where the prior emission source-level provisions of 40 CFR 98.236 for the Onshore Petroleum and Natural Gas Production industry segment and the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment required reporting at either the facility or the sub-basin level (other than the emission source types directly related to wells), the final amendments no longer require reporting at the sub-basin level and instead require reporters to provide emissions and activity data by well-pad ID or gathering and boosting site ID for each facility. For emission source types that report at the unit level (
                        <E T="03">e.g.</E>
                        , AGRs, dehydrators, and flares), there is no change to the reporting level but reporters are required to identify the well-pad ID or gathering and boosting site ID. This requirement replaces reporting of the county or sub-basin ID, if applicable.
                    </P>
                    <P>
                        Due to the change of the level of aggregation of activity data to the well level or well-pad site level within the Onshore Petroleum and Natural Gas Production and Onshore Petroleum industry segment, the EPA is also finalizing changes to the data elements for which reporters with wildcat wells and/or delineation wells may delay reporting for 2 years. Wildcat and delineation wells are considered exploratory wells in the oil and gas industry, and data from these wells are generally considered sensitive information by the industry. State oil and gas commissions commonly hold such data from public release for two years. Based on consideration of public comments, we are finalizing provisions allowing reporters to delay reporting of the following inputs to emission equations for wildcat wells and/or delineation wells for 2 years to acknowledge the sensitive nature of the data and to ensure that the data cannot be back calculated prior to the end of the 2-year delay.
                        <SU>39</SU>
                        <FTREF/>
                    </P>
                    <FTNT>
                        <P>
                            <SU>39</SU>
                             See section III.C.4. of this preamble for a description of the provisions for delayed reporting of inputs to emission equations for mud degassing wildcat wells and/or delineation wells.
                        </P>
                    </FTNT>
                    <P>For completions and workovers with hydraulic fracturing, if the well is a wildcat well or delineation well:</P>
                    <P>• 40 CFR 98.236(g)(5)(i)—Cumulative gas flowback time, in hours, for all completions or workovers at the well from when gas is first detected until sufficient quantities are present to enable separation, and the cumulative flowback time, in hours, after sufficient quantities of gas are present to enable separation.</P>
                    <P>• 40 CFR 98.236(g)(5)(ii)—If the well is a measured well for the sub-basin and well-type combination, the flowback rate, in standard cubic feet per hour.</P>
                    <P>• 40 CFR 98.236(g)(5)(iii)(A)—If you used equation W-12C, gas to oil ratio for the well in standard cubic feet of gas per barrel of oil.</P>
                    <P>• 40 CFR 98.236(g)(5)(iii)(B)—If you used equation W-12C, volume of oil produced during the first 30 days of production after completions of each the newly drilled well or well workover using hydraulic fracturing.</P>
                    <P>For completions and workovers without hydraulic fracturing, if the well is a wildcat well or delineation well:</P>
                    <P>• 40 CFR 98.236(h)(1)(iii)—For a well with one or more gas well completions without hydraulic fracturing and without flaring, total number of hours that gas vented directly to the atmosphere during venting for all completions in the sub-basin category without hydraulic fracturing.</P>
                    <P>• 40 CFR 98.236(h)(1)(iv)—For a well with one or more gas well completions without hydraulic fracturing and without flaring, average daily gas production rate for all completions without hydraulic fracturing in the sub-basin without flaring.</P>
                    <P>• 40 CFR 98.236(h)(2)(iii)—For a well with one or more gas well completions without hydraulic fracturing and with flaring, total number of hours that gas routed to a flare during venting for all completions without hydraulic fracturing.</P>
                    <P>• 40 CFR 98.236(h)(2)(iv)—For a well with one or more gas well completions without hydraulic fracturing and with flaring, average daily gas production rate for all completions without hydraulic fracturing with flaring.</P>
                    <P>For well testing, if the well is a wildcat well or delineation well:</P>
                    <P>• 40 CFR 98.236(l)(1)(iv)—For an oil well not routed to a flare, average gas to oil ratio for the tested well.</P>
                    <P>• 40 CFR 98.236(l)(1)(iv)—For an oil well not routed to a flare, average gas to oil ratio for the tested well.</P>
                    <P>• 40 CFR 98.236(l)(1)(v)—For an oil well not routed to a flare, average flow rate for the tested well.</P>
                    <P>• 40 CFR 98.236(l)(2)(iv)—For an oil well routed to a flare, average gas to oil ratio for the tested well.</P>
                    <P>• 40 CFR 98.236(l)(2)(v)—For an oil well routed to a flare, average flow rate for the tested well.</P>
                    <P>• 40 CFR 98.236(l)(3)(iii)—For a gas well not routed to a flare, number of well testing days for the tested well in the calendar year.</P>
                    <P>• 40 CFR 98.236(l)(3)(iv)—For a gas well not routed to a flare, average annual production rate for the tested well.</P>
                    <P>• 40 CFR 98.236(l)(4)(iii)—For a gas well routed to a flare, number of well testing days for the tested well in the calendar year.</P>
                    <P>• 40 CFR 98.236(l)(4)(iv)—For a gas well routed to a flare, average annual production rate for the tested well.</P>
                    <P>
                        For associated gas venting and flaring, if the well is a wildcat well or delineation well:
                        <PRTPAGE P="42104"/>
                    </P>
                    <P>• 40 CFR 98.236(m)(5)—Volume of oil produced by the well in the calendar year only during the time periods in which associated gas was vented or flared.</P>
                    <P>• 40 CFR 98.236(m)(6)—Total volume of associated gas sent to sales or used on site and not sent to a vent or flare in the calendar year only during time periods in which associated gas was vented or flared.</P>
                    <P>Reporters are not allowed to delay reporting of any of the emissions from these sources, nor are they allowed to delay reporting of any other data elements in 40 CFR 98.236. Providing a 2-year delay in reporting for these specific inputs protects sensitive information during the time in which it is considered to be sensitive information by the industry. After 2 years have passed, reporters will be required to report these inputs to emission equations. We emphasize that this information would be considered to be emission data under CAA section 114 that is not eligible for confidential treatment upon submission to the agency, and thus will be made available to the public upon submission. Furthermore, emissions from any well with well degassing must still be reported annually and we further note that we have other information that will allow verification of reported emissions. Moreover, the EPA intends to be diligent in reviewing and reconciling delayed data with reported emissions data, and we also stress that, although the delayed data may not be reported in the initial reporting year, reporters must maintain records supporting their emission calculations and these records are subject to review by the EPA. Finally, the EPA intends to further evaluate whether this information will be required and, if so, may require reporting without delay in a future rulemaking.</P>
                    <HD SOURCE="HD3">2. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to disaggregate reporting requirements within the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments.</P>
                    <P>
                        <E T="03">Comment:</E>
                         The EPA received several comments asserting that the EPA has not presented a clear rationale rooted in the EPA's statutory authority for the proposed requirement to disaggregate current reporting levels in the Onshore Production and Onshore Gathering and Boosting industry segments.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         With the exception of a clarifying amendment to 40 CFR 98.236(aa)(10)(v) discussed elsewhere in this section, the EPA is finalizing the amendments affecting the aggregation of data reported within the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments as proposed.
                    </P>
                    <P>As stated in section III.D. of the preamble to the 2023 Subpart W Proposal, the aggregation of data currently collected for these industry segments “can present challenges in the process of emissions verification, with corresponding potential impacts on data quality, and it also limits data transparency.” Prior to the amendments finalized in this rulemaking, emissions and activity data for certain emission sources in the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments were reported at the basin or county/sub-basin level. Sources that previously reported at the facility (basin) level include natural gas pneumatic devices, blowdown vent stacks, and equipment leaks. Emission sources that reported at the sub-basin or county level included liquids unloading, completions and workovers with hydraulic fracturing, and storage tanks. This level of aggregation can cover a wide geographic area and include numerous well-pads or gathering and boosting sites. As a result, certain methods of emissions verification are not possible or limited in utility for these sources. For example, a verification review looking at data reported year-over-year for an individual gathering and boosting site may be able to identify data entry errors (e.g., a decimal point entered at the wrong order of magnitude) that would be masked at higher levels of aggregation. Identification of similar types of errors for sources not aggregated at this level regularly occurs during the EPA verification process and has resulted in significant changes (both increases and decreases) to reported emissions.</P>
                    <P>The directive under CAA section 136(h) to ensure that reporting under subpart W accurately reflects total methane emissions is inexorably linked to verification of reported data. Absent a robust system of emissions verification, the EPA cannot ensure the accuracy of reported data. As such, the proposed amendments to improve the quality and verification of subpart W data are supportive of the directive of CAA section 136(h). Further, as discussed in section II.C. of the preamble to the 2023 Subpart W Proposal, beyond carrying out the requirements of CAA section 136, the data collected under subpart W is used to support a range of policies and initiatives under the CAA including but not limited to “provisions involving research, evaluating and setting standards, endangerment determinations, or informing EPA non-regulatory programs.” The final amendments affecting the aggregation of data reported within the Onshore Petroleum and Natural Gas Production reporting requirements are expected to further the EPA's understanding of the industry for future purposes of carrying out provisions under the CAA.</P>
                    <P>One commenter asserted that changes in the aggregation of reported data would not impact the total emissions reported under subpart W. The EPA notes that the intent of the amendments to the aggregation of data for these industry segments is not to increase or decrease overall emissions reported, but to support the verification of reported data and provide a higher degree of data quality and transparency to ensure accuracy of total emissions reported, and that such verification may identify errors that would have resulted in either over- or under- statement of emissions. Further, the EPA anticipates that preparation of more granular reports may provide reporters the opportunity to identify errors that would have resulted in over- (or under-) statement of emissions. We also expect that for facilities subject to the waste emission charge under CAA section 136, that facilities will want to review their data at a more granular level, to ensure that any charges are accurate.</P>
                    <P>
                        In addition to improving the quality and transparency of data collected under subpart W, the amendments affecting the aggregation of data reported within the Onshore Petroleum and Natural Gas Production will support the EPA's implementation of the WEC under CAA section 136. For example, CAA section 136(f)(7) requires that, “[c]harges shall not be imposed with respect to the emissions rate from any well that has been permanently shut-in and plugged in the previous year in accordance with all applicable closure requirements, as determined by the Administrator.” Prior to the amendments finalized in this rulemaking, emissions from liquids unloading, workovers with hydraulic fracturing, and workovers without hydraulic fracturing were reported by sub-basin and emissions from leaks associated with the wellhead were reported at the facility (basin) level. This level of aggregation is not compatible with being able to determine 
                        <PRTPAGE P="42105"/>
                        the “emissions rate from any well” as required by CAA section 136(f)(7). Following these amendments, data for leaks associated with a wellhead will be reported at the well-pad site level while liquids unloading and workovers will be reported by well ID, which can be associated directly with a well that has been permanently shut-in and plugged.
                    </P>
                    <P>Additionally, the EPA notes that existing subpart W requirements specify calculation of emissions at the well level for certain sources, including Well Venting for Liquids Unloading, Completions and Workovers with Hydraulic Fracturing, Completions and Workovers without Hydraulic Fracturing, Well Testing and Associated Gas. The EPA is not changing the level at which these calculations are required to be performed, just the level at which they are reported. It is also noted that certain other sources including flare stacks, AGRs, and enhanced oil recovery (EOR) pumps are already reported at the unit level. The EPA does not anticipate significant burden related to the change in aggregation of reported data for these sources.</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter stated that the proposed reporting requirement for “each gathering and boosting site located in the facility” at 40 CFR 98.236(aa)(10)(v) was unclear as to whether reporters are required to report information for sites that are shutdown, bypassed, or otherwise have no potential for emissions.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The intent of the referenced reporting requirement is to collect information only for gathering and boosting sites that were operational during the calendar year. For further clarification, 40 CFR 98.236(aa)(10)(v) has been amended to specify that reporting is only required for sites for which there were emissions in the calendar year.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter noted that where reporting would be required by well or by well-pad, the EPA did not propose to change the language for wildcat and delineation wells that specified that reporters may delay reporting certain data elements for 2 years “if the only wells in the sub-basin are wildcat and delineation wells.” The commenter questioned why the EPA did not provide a delay in reporting for single wildcat and delineation wells, for emission sources that must be reported by well, or provide a delay in reporting if the only wells on the well-pad are wildcat and delineation wells, for emission sources that must be reported by well-pad. Finally, the commenter asked whether the use of “and/or” in any provisions referring to a single well is a typo or if a single well can be both a wildcat and delineation well.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         For the existing emission sources that will be required to report emissions and activity data by well or by well-pad site, the EPA reviewed the provisions for specific inputs to emissions equations for which we currently provide or proposed to provide the ability for reporters to choose to delay reporting for wildcat and delineation wells for 2 years to protect sensitive information. As documented in the September 23, 2015 memorandum “Review for Potential Disclosure Concerns for Inputs to Emission Equations Affected by the “2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems,” the EPA determined that certain inputs to emission equations would not be likely to reveal any sensitive information, except for two specific types of exploratory wells, delineation wells and wildcat wells. Information specific to exploratory wells is generally considered sensitive information by the industry, so the EPA determined that these inputs to an emission equation should be directly reported but that reporters may delay reporting of sensitive information. The proposal, consistent with the prior reporting requirements as described in that memorandum, acknowledged the sensitive nature of certain data for exploratory wells.
                    </P>
                    <P>
                        The following paragraphs describe our review for specific source types for which we determined that changes from proposal for the 2-year delay provisions were appropriate. For all source types, we emphasize that all other data, including natural gas emissions, emissions of CH
                        <E T="52">4</E>
                         and CO2, and activity data for which a 2-year delay is not explicitly provided, must be reported in the applicable reporting year. The EPA will be very diligent in reviewing current year and delayed data to verify that emissions originally reported are accurate. In addition, for each of these source types, we note that wildcat and delineation wells are slightly different types of wells, and a single well would not be considered both a wildcat well and a delineation well. Therefore, for source types for which emissions and activity data must be reported by well in the final rule, the provisions for delay of reporting refer to “a wildcat or delineation well.” Provisions that allow a delay in reporting only all the wells at the well-pad site, sub-basin, or facility are wildcat wells, delineation wells, or some of each refer to “wildcat wells and/or delineation wells.”
                    </P>
                    <P>
                        <E T="03">Completions and workovers with hydraulic fracturing.</E>
                         The proposal provided a 2-year delay for the reporting of certain data elements for wildcatand/or delineation wells, but only when all wells with completions and workovers with hydraulic fracturing in the same sub-basin and well-type combination were wildcat and/or delineation wells. The specific data elements included the cumulative amount of time flowback during the initial and separation flowback stages, T
                        <E T="52">p,s</E>
                         and T
                        <E T="52">p,i</E>
                         respectively, and the average gas flowback rate at the beginning of the separation stage (FR
                        <E T="52">s,p</E>
                        ) when using equation W-10A, as well as the for the gas to oil ratio (GOR), GORp, and the volume of oil produced during the first 30 days of production (V
                        <E T="52">p</E>
                        ) when using equation W-12C to calculate a 30-day gas production rate for oil wells when using equation W-10A. However, under the final rule, emissions and associated data elements will be reported at the well level; therefore, publication of the data elements specified above even when not all wells in the sub-basin are wildcat or delineation wells may reveal sensitive information. Therefore, we are finalizing the reporting requirements for completions and workovers with hydraulic fracturing to continue providing the option for the 2-year delay in reporting these data elements but we are no longer requiring that all wells in the sub-basin be wildcat and/or delineation wells for reporters to be able to use the 2-year delay.
                    </P>
                    <P>
                        <E T="03">Completions and workovers without hydraulic fracturing.</E>
                         The proposal provided a 2-year delay for the reporting of certain data elements for wildcat and/or delineation wells, but only when all wells with completions and workovers without hydraulic fracturing in the same sub-basin and well-type combination were wildcat and/or delineation wells. The specific data elements included the average daily gas production required by 40 CFR 98.236(h)(1)(iv) and (h)(2)(iv). However, under the final rule, emissions will be reported at the well level; therefore, publication of this information even when not all wells in the sub-basin are wildcat or delineation wells may reveal sensitive information. Therefore, we are finalizing the reporting requirements for completions and workovers without hydraulic fracturing to continue providing the option for the 2-year delay in reporting these data elements, but we are no longer requiring that all wells in the sub-basin be wildcat and/or delineation wells for reporters to be able to use the 2-year delay. In addition, we are 
                        <PRTPAGE P="42106"/>
                        allowing reporters the option of a 2-year delay in reporting the total number of hours that gas is vented or flared, 40 CFR 98.236(h)(1)(iii) or (h)(2)(iii). Equation W-13B computes the quantity of natural gas emissions by multiplying the average daily gas production rate by the number of hours gas is vented or routed to a flare. Under the proposed rule, reporters would have been required to report without a delay the natural gas emissions and the total hours that gas is vented or routed to a flare, but this would have allowed back-calculation of the production rate at the well level.
                    </P>
                    <P>
                        <E T="03">Well testing.</E>
                         The proposal provided a 2-year delay for the reporting of certain data elements for wildcat and/or delineation wells, but only when all wells tested in the same sub-basin were wildcat and/or delineation wells. The specific data elements included the average flow rate in equation W-17A for oil wells and the average annual production rate for gas wells in equation W-17B. However, under the final rule, emissions and associated data elements will be reported at the well level and publication of the data elements discussed above even when not all wells in the sub-basin are wildcat or delineation wells may reveal sensitive information. Therefore, we are finalizing the reporting requirements for well testing to continue providing the option for the 2-year delay in reporting these data elements, but we are no longer requiring that all wells in the sub-basin be wildcat and/or delineation wells for reporters to be able to use the 2-year delay. In addition, for oil wells, we are allowing reporters the option of a 2-year delay in reporting the average GOR for the well in equation W-17A in the final rule, and for gas wells, we are allowing reporters the option of a 2-year delay in reporting the number of well testing days in equation W-17B in the final rule. Reporters use equation W-17A to calculate natural gas emissions from oil wells by multiplying the GOR by the flow rate in barrels of oil per day by the number of days wells are tested. The proposal only provided a 2-year delay for the flow rate. Reporting of all other data elements would allow back calculation of the flow rate; therefore, the EPA is finalizing the rule today to provide the 2-year reporting delay for average GOR. Equation W-17B computes the quantity of natural gas emissions by multiplying the average annual gas production rate by the number of days. Under the proposed rule, reporters would have been required to report without a delay the natural gas emissions and the total number of days, which would have allowed back-calculation of the production rate.
                    </P>
                    <P>
                        <E T="03">Associated natural gas.</E>
                         The proposal provided a 2-year delay for the reporting of certain data elements for wildcat and/or delineation wells, but only when all wells with associated natural gas in the same sub-basin were wildcatand/or delineation wells. The specific data elements included the volume of oil produced and the volume of associated gas sent to sales in 40 CFR 98.236(m)(5) and(6) when using equation W-18. However, under the final rule, associated gas emissions and related data will be reported at the well level and publication of certain data related to associated gas venting and flaring even when not all wells in the sub-basin are wildcat or delineation wells may reveal sensitive information. Therefore, we are finalizing the reporting requirements for associated gas to continue providing the option for the 2-year delay for volume of oil produced and volume of gas sent to sales but we are no longer requiring that all associated gas wells in the sub-basin be wildcat and/or delineation wells for reporters to be able to use the 2-year delay.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Multiple commenters disagreed with the proposed definition of a “centralized oil production site” and its proposed designation as a site type for facilities in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment. Commenters requested that the term “centralized oil production site” be revised to “centralized production facility,” the associated definition be revised to match the definition of the term in the NSPS OOOOb and EG OOOOc regulations, and that the site type be designated as part of the Onshore Petroleum and Natural Gas Production industry segment. Commenters asserted that the proposed definition and placement within the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment were inconsistent with CAA section 136.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA is finalizing the definition of “centralized oil production site” as proposed. The EPA notes that the EPA did not reopen, and no change was proposed nor is being finalized in this rulemaking to, the industry segment definitions for “Onshore petroleum and natural gas production” and “Onshore petroleum and natural gas gathering and boosting” at 40 CFR 98.230(a)(2) and (9), respectively, nor the definitions of facilities with respect to this industry segment in 40 CFR 98.238. The EPA is finalizing one minor revision to the industry segment definition for “Onshore petroleum and natural gas gathering and boosting” in this rulemaking, at 40 CFR 98.230(a)(9), to clarify the EPA's original intent that the petroleum and/or natural gas is transported to a downstream endpoint, as is already clear from the definition of “gathering and boosting system” in 40 CFR 98.238 (see section III.U.3. of this preamble for additional information). However, this revision does not substantively change the industry segment definition. The EPA did not reopen, and no change was proposed nor is being finalized in this rulemaking to, the definition of facility with respect to this industry segment in 40 CFR 98.238. The new reporting element of a site type (including the newly defined centralized oil production site) for facilities in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment does not change the applicable industry segment for reporting facilities, either before or after this rulemaking comes into effect. In other words, existing sites that meet the new “centralized oil production site” definition are currently considered to be part of the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment and will continue to be considered part of this segment with this final rule. The distinction between an Onshore Petroleum and Natural Gas Production facility and an Onshore Petroleum and Natural Gas Gathering and Boosting facility under the existing and finalized subpart W is primarily based on whether the equipment is located on a single well-pad or associated with a single well-pad (onshore production equipment) or located off a single well-pad and associated with two or more single well-pads (gathering and boosting equipment). Centralized oil production sites are distinct from the separately defined well-pad sites and receive hydrocarbon liquids from two or more single well-pads. Therefore, these sites do not meet the criteria for inclusion in an Onshore Petroleum and Natural Gas Production facility as defined in subpart W.
                    </P>
                    <P>
                        Although implementation of CAA section 136(c) (“Waste Emissions Charge”) is outside the scope of this rulemaking, the EPA notes that CAA section 136(d) defines the term “applicable facility” as a facility within specified industry segments as defined in subpart W. Thus, this approach is consistent with the existing facility definitions in subpart W referenced in CAA section 136 when the statutory provision was enacted. As previously 
                        <PRTPAGE P="42107"/>
                        noted, the EPA did not propose and is not finalizing changes to the definition of the “Onshore petroleum and natural gas gathering and boosting” industry segment (beyond the minor clarification noted in the previous paragraph) or the definition of a facility with respect to this segment, and as such the request to change this definition is outside the scope of this rulemaking.
                    </P>
                    <HD SOURCE="HD2">E. Natural Gas Pneumatic Device Venting and Natural Gas Driven Pneumatic Pump Venting</HD>
                    <P>
                        Subpart W currently requires calculation of GHG emissions from natural gas pneumatic device venting (existing 40 CFR 98.233(a)) and natural gas driven pneumatic pump venting (existing 40 CFR 98.233(c)) using default population emission factors multiplied by the number of devices and the average time those devices are “in-service” (
                        <E T="03">i.e.,</E>
                         supplied with natural gas). In our 2022 Proposed Rule, we proposed to update the population emission factors for pneumatic devices based on recent study data. In the 2023 Subpart W Proposal, we proposed adding calculation methods based on measurements and leak screening for all pneumatic device types while retaining the option to use population emission factors for continuous bleed pneumatic devices only. For intermittent bleed pneumatic devices, the 2023 Subpart W Proposal removed the option to use default population emission factors allowing only measurement and leak screening methods to be used. In this final rule, after consideration of the comments received, we are finalizing measurement options similar to those included in the 2023 Subpart W Proposal, updating from proposal to allow facilities the option to use population emission factors for all pneumatic device types (including intermittent bleed devices), and updating the default population emission factors for all pneumatic device types (including intermittent bleed devices) as proposed in the 2022 Proposed Rule and consistent with request for comments on this approach included in the 2023 Subpart W Proposal. Therefore, in the final rule, up to four calculation methods are provided as described in this section.
                    </P>
                    <P>As proposed, we are expanding the number of industry segments that have to report natural gas pneumatic device venting to include Onshore Natural Gas Processing and Natural Gas Distribution industry segments. However, we are not finalizing the first portion of the first sentence that was proposed at 40 CFR 98.233(a) listing all of the industry segments that must calculate pneumatic device venting emissions. Listing these industry segments in 40 CFR 98.233(a) is duplicative of the information in 40 CFR 98.232 and inconsistent with how the calculation methods for other emission sources are stated. Similarly, we are deleting the listing of industry segments in the definition of GHGi term in equation W-1B. We are also adding a sentence to 40 CFR 98.233(a) to clarify that references to natural gas pneumatic devices for Calculation Method 1 also apply to combinations of natural gas pneumatic devices and natural gas driven pneumatic pumps that are served by a common natural gas supply line, consistent with the corresponding provisions in 40 CFR 98.233(c). We are making a number of other revisions and clarifications to specific proposed requirements for natural gas pneumatic device venting and natural gas pneumatic pump venting and these are described in the applicable subsections of this section.</P>
                    <HD SOURCE="HD3">1. Direct Measurement Methods for Natural Gas Pneumatic Devices and Natural Gas Pneumatic Pumps</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        Consistent with section II.B. of this preamble, we are finalizing Calculation Method 1 based on direct measurement of natural gas supplied to pneumatic devices in 40 CFR 98.233(a)(1) and supplied to pneumatic pumps in 40 CFR 98.233(c)(1), as proposed, with minor clarifications. If a continuous flow monitoring device is installed on the natural gas supply line dedicated to one or a combination of pneumatic devices, or the natural gas supply line dedicated to one or more pneumatic pumps, that are vented directly to the atmosphere, then the measured flow must be used to calculate the emissions from the pneumatic devices or pneumatic pumps, as applicable, downstream of that flow monitor. We are adding the word “continuous” to indicate that the flow meter is to be used on an ongoing basis, not temporarily. Temporary flow measurements are included under the provisions for Calculation Method 2. We are also finalizing that this calculation method is required when the flow is continuously measured in a supply line that serves both pneumatic devices and natural gas driven pneumatic pumps that are all vented directly to the atmosphere. We are clarifying in the final rule for both pneumatic devices and pneumatic pumps that this requirement applies if the flow monitor is capable of meeting the requirements of existing 98.234(b). In other words, if the flow is continuously measured but the meter is not capable of meeting these requirements, Calculation Method 1 is not required. When using Calculation Method 1, the flow monitor must meet the requirements specified in existing 40 CFR 98.234(b). We are also finalizing as proposed reporting requirements for each measurement location to report the type of flow monitor, the number of each type of pneumatic device being monitored at that location, and an indication of whether any natural gas driven pneumatic pumps are also monitored at that location, and the CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                         emissions calculated for that monitoring location in 40 CFR 98.236(b)(3). We are also finalizing comparable reporting requirements for natural gas driven pneumatic pumps in 40 CFR 98.236(c)(3), as proposed.
                    </P>
                    <P>
                        For natural gas pneumatic devices that install a flow meter dedicated to measuring the flow of natural gas supplied to one or a combination of pneumatic devices that are vented directly to the atmosphere for only a portion of the year, in the final provision we are updating to clarify the proposed requirement to “escalate” the measured flow based on time in service by rephrasing this requirement, consistent with our intent. In the final rule, reporters using continuous flow meters for a portion of the year must calculate the total volumetric (or mass) flow for the year based on the measured volumetric flow times the total hours in the calendar year the devices were in service (
                        <E T="03">i.e.,</E>
                         supplied with natural gas) divided by the number of hours the devices were in service (
                        <E T="03">i.e.,</E>
                         supplied with natural gas) and the volumetric (or mass) flow was being measured. For natural gas pneumatic pumps, we are updating proposed 40 CFR 98.233(c)(1)(i)(A) to use language in the final rule that is consistent with the updates discussed above for “escalating” measured flow for pneumatic devices. As a result, we are also removing proposed equation W-2A from 40 CFR 98.233(c)(1)(i)(A), which is no longer necessary for pneumatic pumps, and renumbering equation W-2B to W-2A and equation W-2C to W-2B.
                    </P>
                    <P>
                        For natural gas pneumatic devices that do not have or do not elect to install a flow meter dedicated to measuring the flow of natural gas supplied to one or a combination of pneumatic devices that are vented directly to the atmosphere, we are finalizing requirements for Calculation Method 2 in 40 CFR 98.233(a)(2) to allow reporters to measure the natural gas emissions from each pneumatic device vented directly to the atmosphere at the well-pad site, gathering and boosting site, or facility, 
                        <PRTPAGE P="42108"/>
                        as applicable, using one of the measurement methods in existing 40 CFR 98.234(b) through (d). For natural gas driven pneumatic pumps that do not have or do not elect to install a flow meter dedicated to measuring the flow of natural gas supplied to one or a combination of pneumatic pumps vented directly to the atmosphere, we are finalizing requirements that the reporter either measure the natural gas emissions from each such pneumatic pump at the facility as specified in 40 CFR 98.233(c)(2) or calculate emissions from each such pneumatic pump at the facility using the default emission factor as specified in 40 CFR 98.233(c)(3). The measurement method is referred to as Calculation Method 2 for pumps and is similar to Calculation Method 2 for pneumatic devices.
                    </P>
                    <P>
                        For reasons discussed in section III.E.3. of this preamble, we are including a fourth calculation method for pneumatic devices allowing the use of default population emission factors and this revision led to us further assessing and updating from proposal Calculation Method 2 in the final rule. We determined that facilities with pneumatic device measurement data for some but not all sites, particularly in industry segments subject to the WEC in section 136(c) through (h) of the CAA, should be able to use those measurements for their subpart W reports. Therefore, in the final rule we are modifying Calculation Method 2 to allow facilities in the Onshore Petroleum and Natural Gas Production and in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segments to elect to use Calculation Method 2 for pneumatic devices for some well-pad sites or gathering and boosting sites and to elect to use other methods for other sites. However, we are specifying that, with the exception of emissions from devices for which natural gas supply is measured according to Calculation Method 1, emissions from all devices within an individual well-pad site or gathering and boosting site must be calculated using the same method (
                        <E T="03">i.e.,</E>
                         Calculation Method 2 or Calculation Method 3 or Calculation Method 4, if applicable) for a given calendar year in order to prevent selective measurements of certain devices within a site that are expected to have lower emissions. This approach is consistent with our approach for equipment leaks where we have allowed and continue to allow site-by-site equipment leak surveys to constitute a complete leak detection survey for facilities in the Onshore Petroleum and Natural Gas Production and in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segments. This approach also encourages the use of Calculation Method 2 for selected well-pads and gathering and boosting sites at facilities that may have otherwise opted to use Calculation Method 4 rather than having to commit to measuring all devices across the large, basin-wide facilities within these industry segments. While we generally use the phrase “well-pads” to refer to sites in the Onshore Petroleum and Natural Gas Production industry segment that would be considered a complete survey, we know there are cases when some pneumatic devices might not be on a well-pad but are still “associated with a single well-pad” (as defined in 40 CFR 98.238). To ensure that the requirements to measure or monitor all pneumatic devices (or equipment leaks) at the site-level for facilities in the Onshore Petroleum and Natural Gas Production industry segment include such devices, we are finalizing the term “well-pad site” in 40 CFR 98.238 and defining the well-pad site to mean all equipment on or associated with a single well-pad, as discussed in section III.D. of this preamble. Thus, the site-level pneumatic device provisions for the Onshore Petroleum and Natural Gas Production industry segment include natural gas pneumatic devices present on a single well-pad and natural gas pneumatic devices that are not on that single well-pad but that are associated with that single well-pad. We are also clarifying that the reporting requirements for sources that are not reported at the equipment level must be reported at the well-pad site level.
                    </P>
                    <P>For facilities in the Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, and Natural Gas Distribution industry segments, the election to use Calculation Method 2 is made at the facility level. In other words, if Calculation Method 2 is elected, all pneumatic devices at the facility (except those for which natural gas supply is measured according to Calculation Method 1) must be measured annually or over a multi-year cycle. We elected to retain this facility-level requirement because facilities in the Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage industry segments are much smaller and less dispersed than the basin-wide facility definitions in the Onshore Petroleum and Natural Gas Production and in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segments, and because these facilities are generally expected to have a lower number of natural gas pneumatic devices where facility-wide monitoring of devices can be accomplished within a day or two. We recognize that facilities in the Natural Gas Distribution industry segment can be very large and may have a significant number of natural gas pneumatic devices, and we recognize that this approach could encourage the use of default population emission factors. However, we have not currently defined nor proposed to define “distribution sites” that account for all site types within this industry segment. Furthermore, facilities in the Natural Gas Distribution industry segment are not subject to the WEC. Based on these considerations, we determined it was appropriate to retain facility-level requirements for the Natural Gas Distribution industry segment.</P>
                    <P>We are finalizing as proposed that the measurement interval for facilities in the Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, and Natural Gas Distribution industry segments be dependent on the number of devices at the facility. For facilities with 25 or fewer natural gas pneumatic devices, we are requiring measurement of all devices annually. For facilities with 26 to 50 devices, we are requiring measurement of all devices in a two-year period. The required interval period increases with every 25 devices, until reaching a maximum cycle time of 5 years for facilities with 101 or more natural gas pneumatic devices that are vented directly to the atmosphere.</P>
                    <P>
                        Under Calculation Method 2, we are finalizing measurement requirements as proposed that each pneumatic device vent measurement, except for isolation valve actuators, must be conducted for a minimum of 15 minutes; measurements for pneumatic isolation valve actuators must be conducted for a minimum of 5 minutes. The reduced monitoring duration for isolation valve actuators is provided because these devices actuate very infrequently, and the monitoring is targeted to confirm the valve actuators are not malfunctioning (
                        <E T="03">i.e.,</E>
                         emitting when not actuating) rather than to develop an average emission rate considering some limited number of actuations. If there is a measurable flow during the measurement period, the average flow rate measured during the measurement period must be used as the average flow rate for that device and multiplied by the total hours the device is in service (
                        <E T="03">i.e.,</E>
                         supplied with natural 
                        <PRTPAGE P="42109"/>
                        gas) to calculate annual emissions (by pneumatic device type). For continuous bleed devices, if there is no measurable flow rate (
                        <E T="03">i.e.,</E>
                         flow rate is below the method detection limit), we are requiring reporters to confirm the device is in service when measured and that the device type is correctly characterized. If the device was not in service, the device must be retested at a time when it is in service. If a continuous high bleed device was correctly characterized and confirmed to be in service, the device must be retested using a different measurement method and/or a longer duration until a measurable flow is detected. When these remeasurements are made, we are adding language to clarify that natural gas emissions from the device must be calculated according to 40 CFR 98.233(a)(2)(iv). For continuous low bleed devices, if there is no measurable flow rate during testing, the manufacturer's steady state bleed rate must be used to estimate the device's emissions. For cases where the manufacturer's steady state bleed rate is not available, but the device is confirmed to be a continuous low bleed pneumatic device, we are adding clarifying language that remeasurement of the device is required. For intermittent bleed devices, if there is no measurable flow rate and the device is determined not to be in service, the device must be retested at a time when it is in service. The lack of any emissions during a 5-minute or 15-minute period, as applicable, when the device is in service would indicate that the device did not actuate and that the device is seating correctly when not actuating. In cases where testing of in-service intermittent bleed devices does not detect measurable flow, we are finalizing as proposed that engineering calculations must be made to estimate emissions per activation and that company records or engineering estimates must be used to assess the number of actuations per year to calculate the emissions from that device for the reporting year. In response to concerns raised by commenters, we are clarifying in the final provisions for Calculation Method 2, consistent with our intent at proposal, that the measurements required under these methods must be made under representative conditions and not immediately after conducting maintenance on the device or after manually actuating the device. These clarifying changes are also being made for Calculation Method 2 for pneumatic pumps.
                    </P>
                    <P>Under Calculation Method 2, if pneumatic device vent measurements are made over several years (as allowed for facilities in the Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, and Natural Gas Distribution industry segments), we are requiring as proposed that all measurements made within a multi-year measurement cycle must be used to calculate a facility-specific emission factor by device type (continuous high bleed, continuous low bleed, and intermittent bleed). The emissions measurements for the pneumatic device vents measured during the reporting year must be used directly for those devices and reporters must use the facility-specific emission factor (by device type) to calculate the emissions from the pneumatic devices that were not measured during the reporting year.</P>
                    <P>
                        In the final rule, we are not finalizing the proposed Calculation Method 2 reporting requirements for Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Boosting and Gathering industry segments pertaining to multi-year measurement cycles as this is no longer an option for facilities in these industry segments in the final rule. Reporters in these industry segments must still report other Calculation Method 2 data elements for each well-pad site or gathering and boosting site, as applicable, consisting of the total number of natural gas pneumatic devices by type measured in the reporting year, the primary measurement method, the average time the devices were in service (
                        <E T="03">i.e.,</E>
                         supplied with natural gas) during the calendar year, and the GHG emissions for each type of natural gas pneumatic device.
                    </P>
                    <P>
                        As proposed, reporters in the Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, and Natural Gas Distribution industry segments using Calculation Method 2 would report for each facility, the total number of natural gas pneumatic devices by type, the number of years in the measurement cycle, the number of devices measured in the reporting year, the primary measurement method (when emissions were measured), the value of the emission factor for the reporting year as calculated using equation W-1A and the devices upon which the emission factor is based, the average time the devices were in service (
                        <E T="03">i.e.,</E>
                         supplied with natural gas) during the calendar year, and the GHG emissions for each type of natural gas pneumatic device.
                    </P>
                    <P>
                        We are finalizing calculation and reporting requirements as proposed for Calculation Method 2 for pneumatic pumps in 40 CFR 98.233(c)(2) and 40 CFR 98.236(c)(4), respectively. Only facilities in the Onshore Petroleum and Natural Gas Production and in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segments are currently required to report emissions from pneumatic pumps and based on the analysis performed as described in section III.C.1. of this preamble and documented in the subpart W TSD, we are not adding this source type for any other industry segment. As proposed, under the final rule Calculation Method 2 for pneumatic pumps allows measurements to be conducted over multiple years not to exceed 5 years for all pumps at a facility in the Onshore Petroleum and Natural Gas Production or Onshore Petroleum and Natural Gas Gathering and Boosting industry segments. For pneumatic pumps, we are finalizing as proposed that reporters must measure for a minimum of 5 minutes while liquid is continuously being pumped. We are also finalizing requirements, as proposed, that the emissions must be calculated as the product of the measured natural gas flow rate and the number of hours the pneumatic pump was pumping. Under Calculation Method 2 for pneumatic pumps, we are finalizing reporting data elements in 40 CFR 98.236(c)(4) per well-pad site or gathering and boosting site to include the number of years in the measurement cycle; an indication of whether emissions were measured or calculated; the primary measurement method (when emissions were measured); the value of the calculated emission factor, the total number of pumps measured and used in calculating the emission factor, the number of pumps that vented to atmosphere, and the estimated average number of hours per year that the vented pumps were pumping liquid (when the emissions were calculated); the total measured CO
                        <E T="52">2</E>
                         and CH
                        <E T="52">4</E>
                         emissions; and the total calculated CO
                        <E T="52">2</E>
                         and CH
                        <E T="52">4</E>
                         emissions.
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to add direct measurement methods for natural gas pneumatic devices and natural gas pneumatic pumps.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Numerous commenters opposed the requirement to measure all devices at the facility using Calculation 
                        <PRTPAGE P="42110"/>
                        Method 2 within a 5-year period, indicating that this requirement would be overly burdensome. Some commenters suggested allowing facilities to develop a facility-specific emission factor based on a representative sampling of, for example, 20 percent of their pneumatic devices as an alternative to measuring all pneumatic devices. Several commenters suggested allowing the use of population factors to eliminate the burden of the measurement/monitoring requirements proposed, particularly since natural gas pneumatic devices will be phased out as a result of NSPS OOOOb and EG OOOOc regulations.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We recognize that some oil and gas facilities may be geographically dispersed and may contain large numbers of pneumatic devices, so measuring all devices may require significant effort. After considering these comments, for the reasons discussed in section III.E.3. of this preamble, the EPA has decided to provide a fourth calculation method that provides a default population emission factor for all devices. This also led to us further assessing and updating from proposal Calculation Method 2 in the final rule, as explained above, to allow facilities in the Onshore Petroleum and Natural Gas Production and in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segments (those segments we assessed had facilities that were geographically dispersed and contained large numbers of pneumatic devices) to elect to use Calculation Method 2 for pneumatic devices for some well-pad sites or gathering and boosting sites and to elect to use other methods for other sites, subject to certain requirements. Regarding the suggestion to allow one-time measurements on a subset of devices to create site-specific emission factors, we find the proposed requirement to instead measure all devices (over a period of up to 5 years) provides the best approach for developing a representative emission factor. This approach ensures that measurements from all pneumatic devices will ultimately be used in the development of the facility's emission factors rather than allowing measurements of only a subset of pneumatic devices to be used, which could be selected to bias the resulting emission factors low. Also, since the NSPS requirements are expected to phase out these devices across many industry segments, it is unclear how representative the measurements made over the next few years will be for devices that may remain in operation 5 years from now. As such, we did not revise the requirements to allow the development and use of a site-specific emission factor for natural gas pneumatic devices based on a one-time measurement of a subset of devices. However, our final Calculation Method 2 requirements we noted in this response (which allow measurements of natural gas pneumatic devices at some well-pads or gathering and boosting sites using Calculation Method 2 and allow the use of default population emission factors for other sites within that facility) should appropriately address commenters concerns, and should promote the use of measurement data for facilities in the Onshore Petroleum and Natural Gas Production or Onshore Petroleum and Natural Gas Gathering and Boosting industry segments. As we noted, this approach is consistent with our approach for equipment leaks where we have allowed and continue to allow site-by-site equipment leak surveys to constitute a complete leak detection survey for facilities in the Onshore Petroleum and Natural Gas Production or Onshore Petroleum and Natural Gas Gathering and Boosting industry segments.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter suggested that Calculation Method 1 be used on representative number of devices to ensure that measurements or monitoring conducted under Calculation Methods 2 or 3 are accurate and representative. The commenter also recommended that the EPA directly address the issue of timing pre-inspections and repairs before formal measurement and monitoring efforts to comply with GHGRP are carried out to ensure measurements are done randomly with respect to repairs and that the EPA require operators to report the date of measurements and inspections performed for Calculation Method 2 or 3, and the date(s) of any repairs performed on pneumatic controllers, including “resetting” controllers by manually actuating them. According to the commenter, it would be essential to ensure that operators are not manipulating results of Calculation Method 2 or 3 by repairing malfunctioning controllers shortly before inspecting them or measuring their emissions.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We believe it would be difficult to ensure that a subset of devices measured using continuous flow meters (Calculation Method 1) would be representative of the pneumatic devices for which Calculation Method 2 or 3 would be used. We agree that any measurements or monitoring conducted according to Calculation Method 2 or 3 should be done during representative periods, which would preclude monitoring immediately after device repairs or manual actuations to reset the device. Monitoring immediately after repairs or manual actuations of devices that are stuck open would result in underestimating emissions by not capturing the emissions associated with malfunctioning devices and devices stuck open that occurred prior to the repair or manual actuation, and that are likely to reoccur after the repair or manual actuation. Therefore, in the final provisions we have added language in both Calculation Methods 2 and 3 that measurements or monitoring must be conducted during representative conditions and must not be conducted immediately after device repair or manual actuation. With these changes, we expect both Calculation Method 2 and 3 to provide accurate estimates of emissions from pneumatic devices as they are based on direct measurement of emissions, monitoring to identify periods of malfunction, and emission factors representative of average emissions and inclusive of malfunction emissions. Finally, we note that under the final rule, we will still be able use the data obtained when Calculation Method 1 is employed as a way to assess the data collected via Calculation Method 2 or 3. For the reasons stated above, we determined that it is not necessary or appropriate at this time to require that a representative number of devices be measured using continuous flow meters.
                    </P>
                    <HD SOURCE="HD3">2. Intermittent Bleed Pneumatic Device Surveys</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        The EPA is finalizing amendments to subpart W to provide an alternative methodology to calculate emissions from intermittent bleed pneumatic devices based on the results of inspections or surveys, consistent with section II.B. of this preamble. Specifically, we are finalizing provisions in 40 CFR 98.233(a)(3) providing an alternative calculation methodology for facilities in the Onshore Petroleum and Natural Gas Production and in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segments that monitor for malfunctioning intermittent bleed pneumatic devices analogous to a “leaker factor” approach used for equipment leaks. In this final rule, after consideration of concerns raised by commenters regarding the applicability of emission factors developed based on data from Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering 
                        <PRTPAGE P="42111"/>
                        and Boosting industry segments to other segments of the industry, we are limiting this method to Onshore Petroleum and Natural Gas Production and in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segments because our assessment is that those are the only segments for which we have the appropriate data needed to develop the emission factors for this approach at this time. We included this “leaker factor” approach in the 2022 Proposed Rule using data from an API study as presented by Tupper (2019),
                        <SU>40</SU>
                        <FTREF/>
                         and we included this “leaker factor” approach in the 2023 Subpart W Proposed Rule using peer reviewed study data from Luck et al. (2019).
                        <SU>41</SU>
                        <FTREF/>
                         The study presented by Tupper included pneumatic devices predominately at oil and gas production sites; the Luck et al. (2019) study evaluated pneumatic devices exclusively and gathering and boosting compressor stations. We decided to use the Luck 
                        <E T="03">et al.</E>
                         (2019) data in the 2023 Subpart W Proposed Rule because it was peer reviewed and because we did not have raw data from the API study to verify the summary data presented by Tupper. These raw data were ultimately provided by API as part of their comments on the 2023 Subpart W Proposal.
                    </P>
                    <FTNT>
                        <P>
                            <SU>40</SU>
                             Tupper, P. 2019. “API Field Measurement Study: Pneumatic Controllers” presented at the EPA Stakeholder Workshop on Oil and Gas in Pittsburgh, Pennsylvania, on November 7, 2019. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>41</SU>
                             Luck, B., 
                            <E T="03">et al.,</E>
                             2019. “Multiday Measurements of Pneumatic Controller Emissions Reveal the Frequency of Abnormal Emissions Behavior at Natural Gas Gathering Stations.” 
                            <E T="03">Environmental Science &amp; Technology Letters</E>
                             6 (6), 348-352. DOI: 10.1021/acs.estlett.9b00158. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        Because of the differences in the scope of these studies, as discussed in further detail in section III.E.2.b. of this preamble, we are finalizing this “leaker factor” approach using the Tupper (2019) equation parameters for well-pad sites and using the Luck et al. (2019) equation parameters for gathering and boosting sites. We refer to this monitoring/leaker factor approach as Calculation Method 3 for pneumatic devices. As noted in the GRI/EPA (1996) study, natural gas intermittent bleed pneumatic devices in the natural gas processing, transmission, and storage segments are used only for isolation valve actuators.
                        <SU>42</SU>
                        <FTREF/>
                         These isolation valve actuators operate infrequently and have different designs than the pneumatic device controllers used in the production and gathering and boosting industry segments. Therefore, we determined it was inappropriate to use either of these equation factors for the other natural gas industry segments.
                    </P>
                    <FTNT>
                        <P>
                            <SU>42</SU>
                             GRI/EPA, 1996. Methane Emissions from the Natural Gas Industry. Volume 12 Pneumatic Devices. GRI-94/0257.29; EPA-600/R-96-080I. June. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>As proposed, if Calculation Method 3 is elected, all intermittent bleed pneumatic devices that vent to the atmosphere at the well-pad or gathering and boosting site (except those for which natural gas supply is measured according to Calculation Method 1) must be monitored at least once in the calendar year according to the leak detection methods in 40 CFR 98.234(a)(1) through (3), but with a monitoring duration of at least 2 minutes or until a malfunction is identified. As discussed in section III.E.1.b. of this preamble, after consideration of comment, we are clarifying in the final provisions for Calculation Method 3, consistent with our intent at proposal, that monitoring conducted for Calculation Method 3 must be performed under representative conditions and not immediately after conducting maintenance on the device or after manually actuating the device.</P>
                    <P>
                        Because under the final provisions we are allowing different well-pads or gathering and boosting sites at the same facility in the Onshore Petroleum and Natural Gas Production and in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segments to elect to use different calculation methods (and thus are no longer including in the final provisions the proposed requirement to measure or monitor all devices at a facility within a 5-year period), we are specifying that, with the exception of emissions from devices for which natural gas supply is measured according to Calculation Method 1, emissions from all devices within an individual well-pad or gathering and boosting site must be calculated using the same method (
                        <E T="03">i.e.,</E>
                         Calculation Method 2 or Calculation Method 3 or Calculation Method 4, if applicable) for a given calendar year.
                    </P>
                    <P>Under Calculation Method 3, all intermittent bleed pneumatic devices that are vented directly to the atmosphere present at the well-pad or gathering and boosting site (except those for which natural gas supply is measured according to Calculation Method 1) must be monitored to identify malfunctioning devices at least once in the calendar year.</P>
                    <P>
                        As proposed, under the final provisions, if a “leak” is observed from the intermittent bleed pneumatic device for more than 5 seconds during a device actuation, then the device is considered to be “malfunctioning” and the malfunctioning device emission factor (similar to a leaker emission factor) would be applied to that device. However, as discussed in section III.E.2.b. of this preamble, we are including special provisions for devices that actuate for more than 5 seconds during normal operations, such as isolation valves on large diameter pipes, to allow reporters to clearly identify these devices using a permanent tag that includes the allowable actuation time for the device under normal operating conditions. Emissions from intermittent bleed pneumatic devices that were not observed to be malfunctioning must be calculated based on the default emission factor for “properly functioning” intermittent bleed pneumatic devices. We are finalizing as proposed in the definition of the variable “T
                        <E T="52">z</E>
                        ” in equation W-1C that the time that a device is assumed to be malfunctioning must be determined following the same procedures as the determination of the duration of equipment leaks identified during a leak survey conducted under 40 CFR 98.233(q) (see the variable “T
                        <E T="52">p,z</E>
                        ” in equation W-30 for equipment leaks). For example, if only one survey of intermittent bleed natural gas pneumatic devices is conducted during the reporting year, then any device found to be malfunctioning during the survey would be required to be assumed to be malfunctioning for the entire year. This approach effectively assumes that the emissions identified during the monitoring survey are representative of the emissions that occur throughout the year. We recognize that some malfunctioning devices may be repaired, but other devices may also begin to malfunction. Based on our analysis of equipment leak durations as conducted to support leaker factor revisions to subpart W finalized in 2016, we maintain that this is the most representative and accurate assumption when determining emission from leaks during annual or periodic surveys.
                        <SU>43</SU>
                        <FTREF/>
                    </P>
                    <FTNT>
                        <P>
                            <SU>43</SU>
                             De Figueiredo, M., 2016. Memorandum to Docket ID No. EPA-HQ-OAR-2015-0764 regarding “Greenhouse Gas Reporting Rule: Technical Support for Leak Detection Methodology Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems Final Rule.” November 1. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        Under Calculation Method 3, we are also finalizing as proposed requirements that emissions from continuous bleed pneumatic controllers (other than those for which the natural gas supply flow is measured as specified in Calculation Method 1) would be determined either by annually measuring the emissions from the pneumatic device vent 
                        <PRTPAGE P="42112"/>
                        following the methods provided in Calculation Method 2 or by using applicable default population emission factors for continuous high bleed and continuous low bleed pneumatic devices.
                    </P>
                    <P>
                        We are finalizing as proposed reporting requirements for intermittent bleed pneumatic devices for which emissions are calculated using Calculation Method 3 under 40 CFR 98.236(b)(5), except (1) those proposed reporting requirements pertaining to multi-year measurement cycles as this is no longer an option under the final provisions, and (2) those proposed reporting requirements applicable to segments other than Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments, which are not permitted the option to use this methodology under the final provisions. Therefore, reporters using proposed Calculation Method 3 must report for each well-pad or gathering and boosting site, as applicable, the total number of natural gas pneumatic devices by type, the method used to estimate emissions from continuous bleed natural gas pneumatic devices, the frequency of monitoring for intermittent devices, the number of devices at the facility monitored in the reporting year, the number found to be malfunctioning, the average time the malfunctioning devices were assumed to be malfunctioning under 40 CFR 98.236(b)(5), the average time that devices that were monitored but were not detected as malfunctioning year were in service (
                        <E T="03">i.e.,</E>
                         supplied with natural gas) during the calendar year, and the GHG emissions for each type of natural gas pneumatic device. For more information regarding Calculation Method 3 for natural gas intermittent bleed pneumatic devices, see the subpart W TSD, available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to survey intermittent bleed natural gas pneumatic devices.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Similar to the comments received regarding Calculation Method 2, numerous commenters opposed the requirement to monitor all devices at the facility within a 5-year period, indicating that this requirement would be overly burdensome. Some commenters suggested allowing facilities to develop a facility-specific emission factor or fraction of malfunctioning devices based on a representative monitoring of, for example, 20 percent of their intermittent bleed pneumatic devices. Several commenters suggested allowing the use of population factors for intermittent bleed devices to eliminate the burden of the monitoring requirements proposed.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         As explained previously, in the final rule the EPA is adding a fourth calculation method that provides a default population emission factor for all devices. This option, combined with the update from proposal in the final provisions allowing different well-pad or gathering and boosting sites at the same facility in the Onshore Petroleum and Natural Gas Production and in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segments to elect to use different calculation methods, appropriately addresses commenters' concerns regarding the requirement to measure or monitor all natural gas pneumatic devices in such facilities that we agreed could be geographically dispersed and contain a large number of pneumatic devices. Under the final provisions for these industry segments that may use Calculation Method 3, the proposed requirement to measure and monitor all devices at a facility over a period of up to 5 years is not included and instead was updated to a requirement to calculate emissions from all devices within an individual well-pad or gathering and boosting site using the same method (
                        <E T="03">i.e.,</E>
                         Calculation Method 2 or Calculation Method 3 or Calculation Method 4, if applicable) for a given calendar year. Regarding the suggestion to allow monitoring on a subset of devices to create site-specific fraction of malfunctioning devices as opposed to all devices within an individual well-pad or gathering and boosting site, we expect that the fraction of malfunctioning devices will be a function of the age of the device, make and model number of the device, and the number of actuations per year of the device. We also expect that the number of devices found malfunctioning would change based on the implementation of a monitoring survey (assuming some or all of the malfunctioning devices are repaired). Requiring only a subset of devices to be monitored would allow facilities to monitor devices expected to emit at lower rates and bias the resulting emission factor low. Therefore, we find the final requirement to monitor all devices at a site provides the best approach for developing a representative fraction of malfunctioning devices for that year for that site. Also, since the NSPS requirements are expected to phase out these devices across many industry segments, it is unclear how representative the fraction of malfunctioning devices as determined over the next few years will be for devices that may remain in operation 5 years from now. As such, we did not revise the requirements to allow the development and use of a site-specific fraction of malfunctioning intermittent bleed natural gas pneumatic devices. However, we expect that the updates in the final provisions that we discussed earlier in this response to promote the use of monitoring data for facilities in the Onshore Petroleum and Natural Gas Production or Onshore Petroleum and Natural Gas Gathering and Boosting segments, given that they allow monitoring of intermittent bleed natural gas pneumatic devices at some well-pads or gathering and boosting sites using Calculation Method 3 and allow the use of default emission factors for other sites within that facility. This approach is consistent with our approach for equipment leaks where we have allowed and continue to allow site-by-site equipment leak surveys to constitute a complete leak detection survey for facilities in the Onshore Petroleum and Natural Gas Production or Onshore Petroleum and Natural Gas Gathering and Boosting industry segments.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         We received numerous comments regarding the proposed emission factors for properly functioning and malfunctioning intermittent bleed pneumatic devices within the equation for Calculation Method 3. Several commenters suggested that the properly operating device emission factor from Tupper as included in the 2022 Proposed Rule should be used over the factor from Luck et al. (2019) as included in the 2023 Subpart W Proposal. According to these commenters, the Tupper study is more representative because it measured a larger number of devices predominately at production sites whereas Luck study included only gathering and boosting sites and measured emissions from much fewer devices. A couple of commenters suggested developing an aggregated emission factor considering the data from both of these studies and one commenter suggested that the EPA also assess data from Footer 
                        <E T="03">et al.</E>
                         (2023) in developing aggregated emission factors for use with Calculation Method 3. According to one commenter, Allen 
                        <E T="03">et al.</E>
                         (2015) reported a national average of 14.0 scf/hr for controllers (both properly functioning and not properly 
                        <PRTPAGE P="42113"/>
                        functioning) associated with compressors, which is approximately three times the average emission rate for controllers in service of other equipment (5.0 scf/hr for both properly functioning and not functioning properly). Some commenters suggested that the EPA allow reporters to use engineering calculations for intermittent bleed devices determined to be properly functioning in place of or as an alternative to the default emission factor for properly functioning intermittent bleed pneumatic devices.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We agree with commenters that the API/Tupper study was primarily focused on production sites while the Luck study was focused on gathering and boosting sites. After considering these comments, we determined it was appropriate to base the final emission factors on the API/Tupper study for well-pad sites at an Onshore Petroleum and Natural Gas Production or Onshore Petroleum facility because the API/Tupper study was focused on production sites. We also determined it was appropriate to base the final emission factors on Luck et al. (2019) for gathering and boosting sites at an Onshore Petroleum and Natural Gas Gathering and Boosting facility because the Luck study was focused on gathering and boosting sites. We also determined it was appropriate to base the final emission factors on these respective studies because, based on the comparison of pneumatic device emission factors between devices associated with compressors and devices associated with other equipment as presented in Allen et al. (2015),
                        <FTREF/>
                        <SU>44</SU>
                         it is logical to conclude that properly operating intermittent bleed devices at gathering and boosting facilities, which often have more compressors, would have higher emissions per device than devices at onshore production facilities, which have fewer compressors.
                    </P>
                    <FTNT>
                        <P>
                            <SU>44</SU>
                            Allen, D.T., 
                            <E T="03">et al.,</E>
                             2015. “Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States: Pneumatic Controllers.” 
                            <E T="03">Environ. Sci. Technol.</E>
                             49, 633-640. dx.doi.org/10.1021/es5040156. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        For other industry segments, we initially expected that the pneumatic devices used at the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment with its compressor stations would be more analogous to the other mid and downstream industry segments. This is evidenced by the fact that the correctly functioning intermittent bleed device emission factor of 2.8 scf/hr from Luck 
                        <E T="03">et al.</E>
                         (2019) which is based on measurements at gathering and boosting sites, is very similar to the historic population emission factor used in subpart W for the Onshore Natural Gas Transmission Compression industry segment of 2.35 scf/hr, which was based on engineering calculations that assume the device is properly functioning. However, after reviewing available data, we determined that we did not have sufficient data to provide separate malfunctioning and non-malfunctioning emission factors for Calculation Method 3 for Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, and Natural Gas Distribution facilities, and are not allowing Calculation Method 3 as an option for these industry segments at this time. As noted in the GRI/EPA 1996 study, natural gas intermittent bleed pneumatic devices used in the natural gas processing, transmission, and storage industry segments are isolation valve actuators. These isolation valve actuators actuate seldomly and have different designs and functions from the natural gas intermittent bleed pneumatic controllers measured in the API/Tupper study or the Luck 
                        <E T="03">et al.</E>
                         (2019) study. We found no study data available focused on isolation valve actuators at these “downstream” industry segments by which to characterize emissions from malfunctioning devices. For more information on our review of available data on pneumatic devices by industry segment, see the subpart W TSD, available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                    </P>
                    <P>We also considered whether the correctly functioning emission factor should be based on engineering calculations or other measurement data. While we agree that engineering calculations can be accurate, this is the case only when accurate estimates of the actuation frequency can be made, which will not necessarily be the case for all intermittent devices. We also considered that, if reporters could elect to use the default factor for some intermittent bleed devices and use engineering calculations for other devices, facilities would likely use engineering calculations only for those devices that have emissions less than the default and use the default for all other devices, thereby biasing the emissions low and not resulting in accurate total emissions reported. We also note that the use of engineering calculations is allowed under Calculation Method 2 for devices that do not have measurable emissions during the measurement period. Reporters preferring to use device-specific engineering calculations for properly functioning intermittent bleed pneumatic devices are encouraged to use Calculation Method 2. Therefore, we are not providing or allowing facilities to estimate device-specific emissions based on engineering calculations when using Calculation Method 3.</P>
                    <P>
                        <E T="03">Comment:</E>
                         A few commenters noted that some intermittent bleed devices actuate longer the 5 seconds during normal actuations such that assigning these devices as malfunctioning would overstate their emissions when applying Calculation Method 3. One commenter noted that, as an industry rule of thumb, the actuation time for a valve opening and closing is one to two seconds per inch of pipe diameter. According to the commenter, the proposed monitoring methodology would mistakenly designate devices on pipes six inches or greater in diameter as “malfunctioning.” Another commenter noted that throttling intermittent bleed pneumatic devices should not be assumed to be malfunctioning or leaking merely because it actuates for longer than 5 seconds. This commenter recommended that the final rule should provide that an operator must make an engineering determination confirmed by field inspections that a throttling pneumatic device is actually malfunctioning before using the malfunctioning device emission factor.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         While we maintain that the 5-second duration of emissions is reasonable for the vast majority of pneumatic devices, we acknowledge that some larger devices may have actuation times exceeding 5 seconds. Therefore, we are including provisions in the final rule for facilities to 
                        <E T="03">a priori</E>
                         identify those select devices that are expected to have actuation emissions lasting longer than 5 seconds (like an isolation valve on a 12-inch pipe) and the actuation times expected for each of those devices. In the final rule, we are requiring reporters that use Calculation Method 3 to specifically identify those intermittent bleed devices with actuation times longer than 5 seconds using a tagging system or similar method that indicates the expected actuation time for the device. Facilities will also be required to report the number of devices for which they are using extended emission duration provisions. With these and corresponding provisions for devices with longer actuation times, we maintain that the final rule provides adequate provisions to accurately assess whether an intermittent bleed device is properly functioning during a monitoring survey.
                        <PRTPAGE P="42114"/>
                    </P>
                    <HD SOURCE="HD3">3. Revisions to Emission Factors</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>Regarding pneumatic devices, in our 2022 Proposed Rule, we proposed to update the default population emission factors for all device types based on recent study data. In the 2023 Subpart W Proposal, for intermittent bleed devices, we proposed to remove default population emission factors altogether and require measurement or monitoring of these devices. In the proposal, we requested comment on this approach and also requested comment on default population emission factors for intermittent bleed devices in the event that this option was retained in the final rule. In this final rule, under Calculation Method 4, we are allowing the option to continue to use default population emission factors to estimate emissions from both intermittent bleed devices and continuous bleed devices at the well-pad site, gathering and boosting site, or facility level, as applicable. Consistent with the overall intent of this final rulemaking for reporting to be based on empirical data, consistent with section II.B. of this preamble, if measurement or survey data are available, we are requiring that emissions be calculated based on those data when available. Therefore, in the final rule, reporters cannot use Calculation Method 4 for devices for which natural gas supply is measured according to Calculation Method 1 or for devices at sites for which measurements or monitoring were conducted in accordance with Calculation Method 2 or 3. For all other devices, Calculation Method 4 is allowed. Regarding pneumatic pumps, the final method based on a default emission factor is the same as the methodology in 40 CFR 98.233(c) of the existing rule and is referred to as Calculation Method 3 for pneumatic pumps in the final rule. As proposed, for pneumatic pumps we are maintaining the existing default population emission factor.</P>
                    <P>Under Calculation Method 4 for pneumatic devices, we are finalizing that the default population emission factor for continuous low bleed pneumatic devices is 6.8 standard cubic feet per hour per device (scf/hr/device) for all applicable industry segments, based on recent study data and consistent with the 2023 Subpart W Proposal. For continuous high bleed pneumatic devices under Calculation Method 4, consistent with the 2023 Subpart W Proposal, based on recent study data we are finalizing a default population emission factor of 21 scf/hr/device for devices in the Onshore Petroleum and Natural Gas Production and in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segments and a default population emission factor of 30 scf/hr/device for continuous high bleed devices in the Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, and Natural Gas Distribution industry segments.</P>
                    <P>For facilities in the Onshore Petroleum and Natural Gas Production and in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segments, we are finalizing an intermittent bleed pneumatic device default population emission factor of 8.8 scf/hr/device and for facilities in the Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, and Natural Gas Distribution industry segments, we are finalizing an intermittent bleed pneumatic device default population emission factor of 2.3 scf/hr/device, based on recent study data and consistent with those population emission factors that we included in the 2022 Proposed Rule and that we discussed in the preamble to the 2023 Subpart W Proposal and for which we requested comment in the event the final rule included such a method for intermittent bleed devices.</P>
                    <P>For more information regarding this review and development of the emission factors, see the subpart W TSD, available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.</P>
                    <P>Finally, we note that for pneumatic pumps, we are maintaining the existing default population emission factor, as proposed. Reporters that do not have or do not elect to install a flow meter on the natural gas supply line dedicated to any one or more natural gas driven pneumatic pumps and that do not elect to measure the volumetric flow rate of emissions from all the natural gas driven pneumatic pumps vented directly to the atmosphere at a well-pad or gathering and boosting site are required to continue using the current default population emission factor for pneumatic pumps vented directly to the atmosphere under Calculation Method 3 for pneumatic pumps.</P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments and requests for comments on population emission factors for natural gas pneumatic devices and natural gas pneumatic pumps.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Numerous commenters recommended that the EPA provide a default emission factor for intermittent bleed devices. Many commenters supported the EPA's suggested intermittent bleed pneumatic device emission factor of 8.8 scf/hr; a few commenters suggested this default emission factor should be lower. Commenters suggesting a lower emission factor indicated that if the EPA used a device-weighted average, rather than considering averages by study, and had included data from the additional studies review, a lower emission factor would be calculated. Several commenters opposed the proposed default emission factor for continuous low bleed devices of 6.8 scf/hr arguing that it is incongruous for a low bleed device, which is defined as a device with continuous bleed rates less than 6 scf/hr, to have an emission factor greater than 6 scf/hr.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         After considering these and other comments, the EPA is adding a fourth calculation method that provides a default population emission factor for all devices. In the final rule, we are including a default population emission factor of 8.8 scf/hr for intermittent bleed pneumatic devices in the Onshore Petroleum and Natural Gas Production and the Onshore Petroleum and Natural Gas Gathering and Boosting industry segments. For Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, and Natural Gas Distribution industry segments, we are finalizing an intermittent bleed default population emission factor of 2.3 scf/hr. We determined that these are the most appropriate values after considering all available data. Regarding commenters suggesting that we develop the emission factor weighted by the number of device measurements, we decided that may not be representative. First, the Prasino Group, which had high number of device measurements, selected device model numbers to test and tested 30 of each model number. The equal number of measurements by model number is not necessarily reflective of the proportion of devices in use at U.S. production and gathering and boosting facilities. Second, Luck 
                        <E T="03">et al.</E>
                         (2019) measured emissions from pneumatic devices over 76 hours, which is 150 to 300 times longer than other measurement studies. As such, even though Luck et al. (2019) measured fewer devices, their measurements are expected to be much more accurate and representative of device emissions, particularly for devices that may have 
                        <PRTPAGE P="42115"/>
                        excess emissions sporadically over time. Based on the different study approaches and measurement methods, we determined that equally weighting each study's average emission factor was appropriate. We did not include study data from studies that relied entirely or predominately on engineering calculations because those studies would not fully characterize excess emissions from malfunctioning devices, so would likely be biased low. For more information on our development of the final population emission factors, see the subpart W TSD for the final rule, available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                    </P>
                    <P>
                        With respect to the proposed continuous low bleed default population emission factor of 6.8 scf/hr, we maintain that this is the appropriate default population emission factor under Calculation Method 4, as under this method the emission factor needs to account for times the continuous low bleed device may be malfunctioning. Most reporters use the manufacturer's design steady state bleed rates to determine whether a continuous bleed device is classified as low or high bleed. Therefore, they classify a continuous bleed controller as a low bleed device when the manufacturer's design steady state bleed rate is 6 scf/hr or less. However, across numerous measurement studies,
                        <E T="51">45 46 47</E>
                        <FTREF/>
                         the study data show that “malfunctioning” low bleed devices can emit at higher rates than the design steady state bleed rate. That is, devices with steady state bleed rates of less than 6 scf/hr (“low bleed” devices) could often have measured emissions higher the 6 scf/hr. We consider it essential to set the low continuous bleed emission factor at the average emission rate determined across all low bleed devices, including those devices that exhibited excess emissions associating with malfunctioning devices. As such, we maintain that the final low bleed default population emission factor is the most appropriate and accurate value for estimating average emissions from these devices under Calculation Method 4.
                    </P>
                    <FTNT>
                        <P>
                            <SU>45</SU>
                             The Prasino Group (2013). “Determining Emissions Factors for Pneumatic Devices in British Columbia—Final Field Sampling Report.” November 15. Also, “Final Report—For Determining Bleed Rates for Pneumatic Devices in British Columbia.” December 18. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                        <P>
                            <SU>46</SU>
                             Allen, D.T., 
                            <E T="03">et al.</E>
                             (2015). “Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States: Pneumatic Controllers.” 
                            <E T="03">Eviron. Sci. Technol.</E>
                             No. 49, pp. 633-640. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                        <P>
                            <SU>47</SU>
                             Luck, B., 
                            <E T="03">et al.,</E>
                             2019. “Multiday Measurements of Pneumatic Controller Emissions Reveal the Frequency of Abnormal Emissions Behavior at Natural Gas Gathering Stations.” 
                            <E T="03">Environmental Science &amp; Technology Letters 6</E>
                             (6), 348-352. DOI: 10.1021/acs.estlett.9b00158. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <HD SOURCE="HD3">4. Hours of Operation of Natural Gas Pneumatic Devices</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        As proposed, consistent with section II.D. of this preamble, we are finalizing revisions to the definition of variable “T
                        <E T="52">t</E>
                        ” in existing equation W-1 (which is now equation W-1B) in 40 CFR 98.233 and the corresponding reporting requirements in proposed 40 CFR 98.236(b)(4)(ii)(C)(
                        <E T="03">4</E>
                        ), (b)(4)(iii)(C)(
                        <E T="03">4</E>
                        ), and (b)(5)(i)(C)(
                        <E T="03">2</E>
                        ) to use the term “in service (
                        <E T="03">i.e.,</E>
                         supplied with natural gas)” rather than “operational” or “operating,” to clarify the original and current intended meaning of that variable and term. We are making two minor revisions to the proposed calculation requirements within Calculation Method 2 to clarify the requirements with respect to “in service” time. First, we are adding a paragraph at 40 CFR 98.233(a)(2)(iii)(E) to clarify how to use calculate the average measured emission rate using the entire time of the measurement period, not just times when the device is actively actuating, consistent with the rate needed considering “in service” time. Second, we are deleting proposed paragraph at 40 CFR 98.233(a)(2)(v)(C)(
                        <E T="03">6</E>
                        ), which specified how to calculate an annual average emission rate based on actuation volumes and number of actuation cycles and that time “in service.” This average emission rate is not needed under this scenario and is not needed to calculate the emissions under Calculation Method 2. Therefore, we are removing this calculation requirement in the final rule.
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to clarify the time variable and meaning of “in service” time for use in the pneumatic device calculation methods.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Most commenters supported the clarification regarding time in service. A few commenters opposed the use of in service time because, according to these commenters, use of the in service time (default of 8,760 hours per year) assumes that intermittent bleed devices are continuously emitting when applying the population emission factor and even when applying Calculation Method 3 for properly functioning devices. Because intermittent bleed devices do not continuously emit natural gas under normal operations, the commenters suggest that reporters be allowed to use actuation times and cycle counts to determine the time parameter in the pneumatic device emission calculations. According to these commenters, this approach would allow the use of “empirical data” and yield more accurate emissions estimates.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We strongly disagree with the commenters that actuation time rather than in-service time should be used in Calculation Method 3 or 4. The emission factor used in Calculation Method 3 for correctly operating intermittent bleed devices is not the emission rate measured only during an actuation but represents the average emission rate measured across the measurement period and includes periods when the device is actuating AND when it is not. Thus, the emission factor's denominator is the time the device is “in service (
                        <E T="03">i.e.,</E>
                         supplied with natural gas)” and not the time the device was actuating. Therefore, we must use the same definition of time in service when applying the emission factors used in Calculation Method 3 to determine annual emissions. The exact same argument applies when using the default population emission factors in Calculation Method 4. We note that in many studies, no emissions were measured from the devices over a 15-minute period. These “zero” emissions were factored into the average population emission factor in these studies. Because the emission factors were developed considering cumulative emissions released divided by the cumulative time period the device was being measured (including measurement periods when there were no actuations), the only accurate definition of the time variable in the pneumatic device calculation equations is the time in service (
                        <E T="03">i.e.,</E>
                         the time the device is supplied with natural gas). Use of actuation times in these equations would significantly underestimate emissions and would not result in accurate reporting of total emissions. We note that this use of consistent logic in matching between the measurement approach and the calculation approach is reflected within each calculation method. For example, when measurements are made under Calculation Method 2, we require calculation of the average emission rate over the measurement period. We are adding paragraph at 40 CFR 98.233(a)(2)(iii)(E) to clarify how this 
                        <PRTPAGE P="42116"/>
                        calculation is made and that it includes the entire measurement period, not just times when the device is actuating. This is also consistent with how the emission factors are calculated under Calculation Methods 3 and 4 and consistent with the use of “in service” hours for the annual emission calculation. When there is no measurable flow from the device, actuation volumes and number of actuation cycles can be used under Calculation Method 2 to estimate annual emissions from those devices and the time “in service” is not needed. We proposed to require calculation of the annual average emission rate considering the number of hours the device is “in service” but that requirement does not impact the annual emissions rate to be reported for that device. Since the average emission rate is not used in this case, we are removing that paragraph of the calculation procedures for the average emission rate, which was proposed at 40 CFR 98.233(a)(2)(v)(C)(
                        <E T="03">6</E>
                        ).
                    </P>
                    <HD SOURCE="HD3">5. Natural Gas Pneumatic Devices and Natural Gas Driven Pneumatic Pumps Routed to Control</HD>
                    <P>
                        We understand that emissions from some natural gas pneumatic devices and/or natural gas driven pneumatic pumps are routed to control (
                        <E T="03">i.e.,</E>
                         a flare, combustion unit, or vapor recovery system). The population emission factor is based on natural gas vented directly to the atmosphere from these pneumatic devices/pumps and does not accurately reflect emissions from controlled pneumatic devices/pumps. Therefore, consistent with section II.B. of this preamble, we are finalizing as proposed revisions to 40 CFR 98.233(a) and (c) to clarify requirements for calculating emissions from natural gas pneumatic devices and natural gas driven pneumatic pumps, respectively, that are vented directly to the atmosphere versus pneumatic devices/pumps that are routed to control, consistent with the intent of this rule. The EPA received only minor comments regarding natural gas pneumatic devices and natural gas driven pneumatic pumps routed to control. See the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
                    </P>
                    <P>We are finalizing revisions to 40 CFR 98.233(a) and (c) to clarify that the existing population emission factor calculation methodology is intended to apply only to pneumatic devices/pumps vented directly to the atmosphere, as proposed. The new calculation methodologies described in sections III.E.1. and 2. of this preamble also specify that they apply only to pneumatic devices/pumps vented directly to the atmosphere.</P>
                    <P>
                        We are finalizing requirements that flared emissions from natural gas pneumatic devices or pumps are not required to be calculated and reported separately from other flared emissions, consistent with the 2023 Subpart W Proposal. Instead, emission streams from natural gas pneumatic devices or pumps that are routed to flares are required to be included in the calculation of total emissions from the flare according to the procedures in 40 CFR 98.233(n) and reported as part of the total flare stack emissions according to the procedures in 40 CFR 98.236(n), in the same manner as emission streams from other source types that are routed to the flare. Similarly, as proposed, emissions from natural gas pneumatic devices or pumps that are routed to a combustion unit are required to be combined with other streams of the same fuel type and used to calculate total emissions from the combustion unit as specified in 40 CFR 98.233(z) and reported as part of the total emissions from the combustion unit as specified in 40 CFR 98.236(z). We are also finalizing as proposed provisions that specify that reporters would not calculate or report emissions from natural gas pneumatic devices or pumps if the emissions are routed to vapor recovery and are not subsequently routed to a combustion device (
                        <E T="03">e.g.,</E>
                         are routed back to process or sales). Finally, we are making clarifying edits to the language in 40 CFR 98.233(c)(4) for pumps that are vented to the atmosphere for part of the year and routed to a flare, combustion, or vapor recovery for another part of the year.
                    </P>
                    <P>We are also finalizing as proposed requirements in 40 CFR 98.236(b)(2) and 98.236(c)(2) to report the total number of continuous low bleed, continuous high bleed, and intermittent bleed natural gas pneumatic devices and the total number of natural gas driven pneumatic pumps at the site (regardless of vent disposition), the number of these devices/pumps that are vented to the atmosphere for at least a portion of the year, and the number of these devices/pumps that are routed to control for at least a portion of the year (which includes natural gas pneumatic devices/pumps routed to a flare, combustion unit, or vapor recovery system). We added a sentence at 40 CFR 98.233(a)(8) and (c)(4) to further clarify these reporting requirements apply even when emissions from the pneumatic devices or pumps are required to be reported under other sources (flares or combustion) or not required to be reported.</P>
                    <HD SOURCE="HD2">F. Acid Gas Removal Unit Vents</HD>
                    <HD SOURCE="HD3">1. Reporting of Methane Emissions From Acid Gas Removal Units</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        Reporters currently report only CO
                        <E T="52">2</E>
                         emissions from AGR vents using one of the four calculation methodologies provided in 40 CFR 98.233(d). The EPA is finalizing as proposed the amendments to 40 CFR 98.233(d) and 98.236(d) to require calculation and reporting of CH
                        <E T="52">4</E>
                         from AGR vents, which will improve the coverage of total CH
                        <E T="52">4</E>
                         emissions reported to subpart W, consistent with section II.A. of this preamble. As proposed, the final amendments provide three calculation methods for reporting of CH
                        <E T="52">4</E>
                         from AGR vents and nitrogen removal unit vents, with modifications from proposal regarding when those methods apply. The final Calculation Method 2 requires, as proposed, that if a vent flow meter is installed, including the volumetric flow rate monitor on a continuous emissions monitoring system (CEMS) for CO
                        <E T="52">2</E>
                        , the reporter must use the annual volume of vent gas from the flow meter and the CH
                        <E T="52">4</E>
                         composition from either a continuous gas analyzer or quarterly gas samples to calculate emissions using equation W-3 (40 CFR 98.233(d)(2)). However, based on consideration of public comments regarding safety concerns with measuring the composition of vent gas if high concentrations of H
                        <E T="52">2</E>
                        S are expected to be present, the EPA is finalizing a modification from proposal in Calculation Methods 2 and 4 for CH
                        <E T="52">4</E>
                         and an amendment to Calculation Methods 2 and 4 for CO
                        <E T="52">2</E>
                         that allows reporters to use Calculation Method 4, modeling simulation via software (40 CFR 98.233(d)(4)), for an AGR even if a vent flow meter, including the volumetric flow rate monitor on a CEMS for CO
                        <E T="52">2</E>
                        , is installed. Reporters who elect to use Calculation Method 4 for an AGR with a vent flow meter will be required to determine the difference between the annual volume of vent gas measured by the vent meter and the simulated annual volume of vent gas (as calculated by new equation W-4D), and report the annual volume of vent gas measured by the vent meter, the simulated annual volume of vent gas from the model, and a reason for the difference in flow rates if the difference (as calculated by new equation W-4D) is greater than 20 percent. The EPA considers the selected 
                        <PRTPAGE P="42117"/>
                        20 percent interval to be low enough to ensure reasonable agreement between the flow rates obtained by the different methods but high enough to reasonably account for the expected uncertainties, as described in more detail in section III.F.1.b. of this preamble.
                    </P>
                    <P>
                        Under the final provisions, if neither a CEMS for CO
                        <E T="52">2</E>
                         nor a vent flow meter is installed, for CH
                        <E T="52">4</E>
                         reporters may use Calculation Method 3, engineering equations, with one exception (40 CFR 98.233(d)(3)) or Calculation Method 4, modeling simulation via software (40 CFR 98.233(d)(4)). For Calculation Method 3, the EPA is finalizing as proposed the revisions to the existing equations W-4A and W-4B and finalizing as proposed the new equation W-4C. With the addition of CH
                        <E T="52">4</E>
                         as a component for these equations, reporters need to have information on four parameters rather than the three they currently need to know. Based on consideration of public comment, the EPA is adding a specification in the final provision that if the volumetric emissions calculated using Calculation Method 3 are less than or equal to 0 cubic feet per year, the reporter may not use this calculation method for either CH
                        <E T="52">4</E>
                         or CO
                        <E T="52">2</E>
                         and must instead use Calculation Method 4. As noted in section III.F.1.b. of this preamble, there could be times when the normal variability in flow rate and concentration measurements could result in concerns with the accuracy of Calculation Method 3, particularly for CH
                        <E T="52">4</E>
                        , and in those cases, modeling simulations can take into account more variables than the final engineering equations, which will result in more accurate emissions calculations. For Calculation Method 4, the EPA is finalizing as proposed the addition of the CH
                        <E T="52">4</E>
                         content of the feed natural gas and the outlet natural gas as parameters that must be used to characterize emissions. This specification is analogous to the existing requirement to use acid gas content of the feed natural gas and the acid gas content of outlet natural gas to characterize CO
                        <E T="52">2</E>
                         emissions.
                    </P>
                    <P>
                        The EPA is also finalizing as proposed the addition of relevant reporting elements for CH
                        <E T="52">4</E>
                         from each AGR to 40 CFR 98.236(d). The additional data elements include annual CH
                        <E T="52">4</E>
                         emissions vented directly to the atmosphere; annual average volumetric fraction of CH
                        <E T="52">4</E>
                         in the vent gas if using Calculation Method 2; additional inputs for Calculation Method 3, depending on the equation used (
                        <E T="03">i.e.,</E>
                         as applicable, the annual average volumetric fraction of CH
                        <E T="52">4</E>
                         in the natural gas flowing out of the AGR, annual average volumetric fraction of CH
                        <E T="52">4</E>
                         content in natural gas flowing into the AGR, annual average volumetric fraction of CO
                        <E T="52">2</E>
                         in the vent gas exiting the AGR and annual average volumetric fraction of CH
                        <E T="52">4</E>
                         in the vent gas exiting the AGR); and the CH
                        <E T="52">4</E>
                         content of the feed natural gas and outlet natural gas if using Calculation Method 4.
                    </P>
                    <P>
                        Under the current provisions of subpart W, reporters with AGRs routed to flares are required to report the CO
                        <E T="52">2</E>
                         emissions from the AGR that pass through the flare as AGR vent emissions, and the emissions that result from combustion of any CH
                        <E T="52">4</E>
                         in the AGR vent stream are reported as flare stack emissions. The EPA proposed to revise subpart W such that AGR vents routed to a flare would follow the same calculation requirements as other emission source types and would begin reporting flared AGR emissions (CO
                        <E T="52">2</E>
                        , CH
                        <E T="52">4</E>
                        , and N
                        <E T="52">2</E>
                        O) separately from vented AGR emissions (CO
                        <E T="52">2</E>
                         and CH
                        <E T="52">4</E>
                        ). While the final flaring provisions differ somewhat from the proposed provisions, as explained in more detail in section III.N. of this preamble, the final amendments generally specify as proposed that vented AGR emissions include only those emissions vented directly to the atmosphere and emissions routed to a flare are considered flare stack emissions. In a similar amendment, we are finalizing as proposed the specification that for AGR vents routed to an engine, reporters will calculate CO
                        <E T="52">2</E>
                        , CH
                        <E T="52">4</E>
                        , and N
                        <E T="52">2</E>
                        O emissions using the provisions of 40 CFR 98.233(z) or subpart C, whichever is applicable to that industry segment. We are also finalizing as proposed the requirement that AGRs routed to an engine or flare for the entire year report the information in amended 40 CFR 98.236(d)(1) except for the calculation method and the CO
                        <E T="52">2</E>
                         and CH
                        <E T="52">4</E>
                         emissions from the unit, if the flare emissions are calculated using continuous monitors, as finalized in 40 CFR 98.233(n). If the AGR routed to an engine or flare only for part of the year, the other information in amended 40 CFR 98.236(d)(1) will be required to be reported for the part of the year in which emissions were vented directly to the atmosphere. Consistent with the final provisions of 40 CFR 98.233(n), if the flow rate and composition of the AGR or NRU stream routed to the flare is determined using a calculation method in 40 CFR 98.233(d), then reporters will be required to provide the information in amended 40 CFR 98.236(d)(1) and (2). In a related amendment, because gas routed to a flare will be calculated and reported as flared emissions and not vented emissions, we are revising the definition of “acid gas removal unit (AGR) vent emissions” to remove the phrase “or a flare,” so that it includes only those acid gas emissions released to the atmosphere.
                    </P>
                    <P>
                        Finally, after consideration of public comments regarding the inconsistent calculation of emissions from AGRs with vapor recovery systems compared to the treatment of emissions routed to vapor recovery systems for other source categories, the EPA is adding provisions for AGR vents routed to vapor recovery systems to final 40 CFR 98.233(d)(11) and correspondingly removing the existing (now redundant) provisions in current 40 CFR 98.233(d)(11) that direct reporters to adjust emissions downward to account for CO
                        <E T="52">2</E>
                         emissions recovered and transferred outside the facility. For AGRs and nitrogen removal units with vents routed to vapor recovery systems and flares, the final provisions in 40 CFR 98.233(d)(11) specify how to account for emissions during periods when emissions from those vents are released directly to the atmosphere instead (
                        <E T="03">i.e.,</E>
                         the vapor recovery system or flare is bypassed). These final provisions are similar to the final provisions for dehydrators routed to vapor recovery systems or flares. Reporters will be required to indicate whether the vent was routed to a vapor recovery system, and if so, whether it was routed for the entire year or only part of the year in 40 CFR 98.236(d)(1)(iv); we are correspondingly removing the existing (now redundant) provisions in current 40 CFR 98.233(d)(1)(iv) to report whether CO
                        <E T="52">2</E>
                         emissions were recovered and transferred outside the facility. Similar to the reporting for AGRs routed to an engine or flare, AGRs routed to a vapor recovery system for the entire year report the information in amended 40 CFR 98.236(d)(1) except for the calculation method and the CO
                        <E T="52">2</E>
                         and CH
                        <E T="52">4</E>
                         emissions from the unit. If the AGR is routed to a vapor recovery system only for part of the year, the other information in amended 40 CFR 98.236(d)(1) is required to be reported for the part of the year in which emissions were vented directly to the atmosphere.
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>
                        This section summarizes the major comments and responses related to the proposed amendments to add reporting of CH
                        <E T="52">4</E>
                         emissions from AGRs.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters expressed concern about the accuracy of Calculation Method 3 for calculating CH4 emissions from AGRs, particularly 
                        <PRTPAGE P="42118"/>
                        equation W-4C, which relies on the AGR inlet and outlet flow rates and compositions. Commenters indicated that the volume of methane vented from AGRs is generally negligible when compared to the overall methane flow through the AGR, and the difference in methane concentration in the AGR inlet and outlet streams may be negligible. Consequently, using this method could potentially yield negative methane emissions values or otherwise inaccurate estimates.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA has considered the comments and agrees that there could be times when the normal variability in flow rate and concentration measurements could result in concerns with the accuracy of Calculation Method 3; however, the EPA does not find it appropriate to remove the ability to use Calculation Method 3 or equation W-4C in all cases. Therefore, in response to this comment, the EPA is finalizing the addition of a statement in 40 CFR 98.233(d)(3) to indicate that if the annual total volumetric emissions for an AGR or nitrogen removal unit vent calculated using Calculation Method 3 are less than or equal to 0 cubic feet per year, a reporter may not use this calculation method for that vent. Aside from this newly finalized restriction on Calculation Method 3, the existing rule allows reporters to choose between Calculation Method 3 or Calculation Method 4. Therefore, if the calculated emissions are greater than 0 cubic feet per year but the reporter is concerned that the results may not be accurate, the reporter may choose to use Calculation Method 4 instead, as provided by the existing rule.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters noted that subpart W requires Calculation Method 2 if a vent meter is installed, which mandates quarterly sampling of the vented acid gas stream if a continuous gas analyzer is not installed, and asserted that the vent stream typically has high concentrations of H
                        <E T="52">2</E>
                        S and the sampling is therefore difficult and potentially dangerous to conduct. The commenters stated that, for other source types, including tanks and glycol dehydrators, the EPA has acknowledged that simulation software options are provided instead of direct measurement in part due to safety concerns with measurement (
                        <E T="03">e.g.,</E>
                         high temperature of dehydrator vent streams). Commenters also indicated that some permits include modeling requirements for AGRs, similar to dehydrators, but if a vent meter is present on an AGR, subpart W mandates that reporters not use the modeling results, which is also inconsistent with the requirements for dehydrators. Commenters also provided information from published literature regarding the accuracy of simulation software for methane emissions. Commenters encouraged the EPA to allow the use of simulation software for AGR vents even if a vent meter is present.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA has reviewed this comment and the directives of CAA section 136 and determined it is appropriate to provide an allowance to use Calculation Method 4 for AGRs that have a vent meter and for which reporters are currently required to use Calculation Method 2. The EPA agrees that in cases where a vent stream has high concentrations of H
                        <E T="52">2</E>
                        S, there could be safety concerns with collecting the quarterly samples needed to determine the vent gas composition under Calculation Method 2. The EPA recognizes that part of the rationale for the structure and requirements for the original calculation methods is that use of a continuous vent meter to directly measure vent gas volumes was presumed to be more accurate than simulations with inputs based on “engineering estimate and process knowledge based on best available data.” However, based on our assessment of currently available information, in cases where a vent stream has high concentrations of H
                        <E T="52">2</E>
                        S, the EPA agrees that there could be safety concerns with collecting the quarterly samples needed to determine the vent gas composition under Calculation Method 2. Additionally, in this final rule, our assessment is that simulation software algorithms have improved since the original subpart W rulemaking in 2010 and furthermore the EPA is revising Calculation Method 4 as proposed to specify that certain simulation input parameters must be based on certain measurements, which do not have the same associated safety concerns (see section III.F.2. for further information on that revision). These factors should decrease the accuracy concerns between Calculation Methods 2 and 4. Finally, the EPA is also revising the reporting requirements for Calculation Method 4 to require additional verification information from the vent flow meter in such circumstances. The evaluation of the information available to the reporter though the vent flow meter could confirm or improve the results of simulations under Calculation Method 4 even further. If the simulations conducted under Calculation Method 4 do not agree with the measured annual volume of vent gas, then that could be an indication that the simulation results may not be an accurate representation of the emissions. For example, if a reporter conducts a single simulation for the reporting year and that single simulation results in an annual vent gas volume that varies significantly from the measured annual vent gas volume, the reporter could evaluate factors such as whether the simulation parameters are appropriately representative of annual operation or whether the operating parameters vary enough throughout the year that multiple partial-year simulations might better characterize the annual emissions.
                    </P>
                    <P>
                        Therefore, in summary, the EPA is finalizing an allowance for AGRs that have a vent meter to use Calculation Method 4. As part of the final provisions, the EPA is adding a new equation W-4D in 40 CFR 98.233(d) to determine the percent difference between the two vent gas volumes and new requirements to report both vent gas volumes (
                        <E T="03">i.e.,</E>
                         the annual volume of vent gas measured with the vent meter and the simulated total annual volume of vent gas flowing out of the AGR) if Calculation Method 4 is used in 40 CFR 98.236(d)(2)(iii)(O). The final reporting requirements in 40 CFR 98.236(d)(2)(iii)(O) also specify that if the difference between the vent gas volumes is greater than 20 percent as calculated using equation W-4D, the reporter must provide a reason for that difference. As noted previously in this response, the EPA agrees that software simulations have improved and should generally be robust and accurate, and are thus consistent with CAA section 136(h), and also finds that the new information provided by reporters who elect to use Calculation Method 4 for an AGR with a vent flow meter installed will help to verify the data. The uncertainties in measurements provided by continuous vent flow meters are expected to be low (usually less than ±5 percent). The uncertainties in simulation results result from variability in the variety of input parameters that must be provided and uncertainties inherent in the equations built into the simulation flow rate; the overall uncertainty is more difficult to quantify due to the combination of these factors. The EPA considers the selected ±20 percent interval to be low enough to ensure reasonable agreement between the flow rates obtained by the different methods but high enough to reasonably account for the expected uncertainties. This interval is also consistent with an example scale provided in the GHG Protocol's “Short Guidance for Calculating Measurement and Estimation Uncertainty for GHG 
                        <PRTPAGE P="42119"/>
                        Emissions,” in which uncertainties of ±15 percent are considered “Good” and uncertainties of ±30 percent are considered “Fair.” 
                        <SU>48</SU>
                        <FTREF/>
                    </P>
                    <FTNT>
                        <P>
                            <SU>48</SU>
                             GHG Protocol Initiative. Short Guidance for Calculating Measurement and Estimation Uncertainty for GHG Emissions. Available at 
                            <E T="03">https://ghgprotocol.org/sites/default/files/ghg-uncertainty.pdf</E>
                             and in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters requested that the EPA revise subpart W to account for acid gas removal vents routed to vapor recovery systems, to be consistent with other emission source types. Commenters also noted that subpart W does allow reporters to subtract CO
                        <E T="52">2</E>
                         emissions recovered from AGRs and transferred outside the facility, but it does not allow reporters to subtract the gas from AGR vent streams that are sent to acid gas injection wells or sequestered underground. The commenters stated that the EPA has previously stated that streams that are subsequently injected underground or geologically sequestered must be reported as emissions because the purpose of the GHG Reporting Program is to “collect[] data to inform future climate change policies.” 
                        <SU>49</SU>
                        <FTREF/>
                         However, commenters asserted that this position is not consistent with the intent of the Inflation Reduction Act, so the EPA should amend subpart W to allow reporters to subtract the gas from AGR vent streams that are sent to acid gas injection wells or sequestered underground because those streams are not emitted to the atmosphere.
                    </P>
                    <FTNT>
                        <P>
                            <SU>49</SU>
                             U.S. EPA, 
                            <E T="03">Mandatory Greenhouse Gas Reporting Rule Subpart W—Petroleum and Natural Gas: EPA's Response to Public Comments</E>
                             at 1475 (Nov. 30, 2010). Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        <E T="03">Response:</E>
                         As the commenters noted, the EPA's historic position on the issue of injection and sequestration for subpart W is outlined in 
                        <E T="03">Mandatory Greenhouse Gas Reporting Rule Subpart W—Petroleum and Natural Gas: EPA's Response to Public Comments:</E>
                         “In the final rule establishing the GHG Reporting Program (74 FR 56260, October 30, 2009), the EPA was clear that subpart methods and calculation procedures must be followed whether or not there is subsequent injection underground or geologic sequestration. The GHG Reporting Program is not an emissions inventory; rather it is a reporting program that collects data to inform future climate change policies. The same rationale applies to subpart W in this final action. Data on CO
                        <E T="52">2</E>
                         from an acid gas recovery unit is needed by the EPA to inform future climate change policies, even if the CO
                        <E T="52">2</E>
                         stream is subsequently injected underground. Therefore, such CO
                        <E T="52">2</E>
                         streams must report for the AGR unit emission source.” 
                        <SU>50</SU>
                        <FTREF/>
                    </P>
                    <FTNT>
                        <P>
                            <SU>50</SU>
                             U.S. 
                            <E T="03">EPA, Mandatory Greenhouse Gas Reporting Rule Subpart W—Petroleum and Natural Gas: EPA's Response to Public Comments,</E>
                             November 2010, response to comment EPA-HQ-OAR-2009-0923-0582-31. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        In August 2022, section 136 was added to the CAA. Section 136(c) of the CAA states that “the Administrator shall impose and collect a charge on methane emissions that exceed an applicable waste emissions threshold under subsection (f) from an owner or operator of an applicable facility that reports more than 25,000 metric tons of carbon dioxide equivalent of greenhouse gases emitted per year pursuant to subpart W,” and per CAA section 136(h), the emissions reported under subpart W of the GHGRP must “accurately reflect the total methane emissions and waste emissions from the applicable facilities.” While subpart W of the GHGRP will continue to be used “to inform future climate change policies,” due to the provisions in CAA section 136(h), the EPA must also revise reporting for subpart W to accurately reflect total emissions. Although the WEC will be imposed based on methane emissions, it is also important for CO
                        <E T="52">2</E>
                         emissions to be accurate for purposes of comparing facility CO
                        <E T="52">2</E>
                        e emissions to the threshold in CAA section 136(c).
                    </P>
                    <P>
                        The EPA has also reviewed the requirements for other emission source types in subpart W and agrees with the commenters that for other emission sources, subpart W provides provisions specific to vapor recovery systems regardless of final disposition of the gas. Therefore, after further consideration, the EPA is finalizing provisions for AGR and nitrogen removal unit vents routed to vapor recovery that are similar to the provisions for dehydrators and atmospheric storage tanks routed to vapor recovery systems. The final provisions require the reporters to determine emissions from the vent prior to the vapor recovery system and then adjust those emissions to only report the emissions that are not recovered and are released directly to the atmosphere. These provisions will apply for all AGR vents routed to vapor recovery systems, regardless of whether the recovered gas is transferred outside the facility, injected underground, or sent elsewhere in the facility (
                        <E T="03">e.g.,</E>
                         routed back to the process). Specifically, the EPA is amending 40 CFR 98.233(d) to remove the provisions related to CO
                        <E T="52">2</E>
                         emissions recovered and transferred outside the facility in current 40 CFR 98.233(d)(9) and replace them with provisions for calculating the emissions vented directly to atmosphere from AGRs or nitrogen removal units routed to vapor recovery systems or flares in 40 CFR 98.233(d)(11). Similarly, the EPA is removing the requirement in current 40 CFR 98.236(d)(1)(iv) to report whether any CO
                        <E T="52">2</E>
                         emissions from the acid gas removal unit were recovered and transferred outside the facility. The CO
                        <E T="52">2</E>
                         emissions recovered and transferred outside the facility will continue to be reported under 40 CFR part 98, subpart PP (Suppliers of Carbon Dioxide) rather than subpart W, as currently required.
                    </P>
                    <HD SOURCE="HD3">2. Calculation Method 4</HD>
                    <P>
                        The EPA is finalizing several revisions related to Calculation Method 4 for acid gas removal units as described in this section. The EPA received only minor comments regarding Calculation Method 4 for acid gas removal units. See the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
                    </P>
                    <P>
                        Reporters with AGRs that elect to calculate emissions using Calculation Method 4 are currently required to calculate emissions using any standard simulation software package that uses the Peng-Robinson equation of state and speciates CO
                        <E T="52">2</E>
                         emissions. According to existing 40 CFR 98.233(c)(4), the information that must be used to characterize emissions include natural gas feed temperature, pressure, flow rate, and acid gas content; outlet natural gas acid gas content and temperature; unit operating hours; and solvent temperature, pressure, circulation rate, and weight. These parameters currently must be determined for typical operating conditions over the calendar year by engineering estimate and process knowledge based on best available data. Consistent with section II.B. of this preamble, we are finalizing as proposed that the input parameters related to the natural gas feed that are used for the simulation software must be obtained by measurement. Those parameters include natural gas feed temperature, pressure, flow rate, acid gas content, CH
                        <E T="52">4</E>
                         content, and, for nitrogen removal units, nitrogen content. We are finalizing as proposed that reporters collect measurements reflective of representative operating conditions over the time period covered by the simulation. We did not propose and are not finalizing any changes to the 
                        <PRTPAGE P="42120"/>
                        requirement that the other parameters must be determined for operating conditions over the time period covered by the simulation based on engineering estimate and process knowledge.
                    </P>
                    <P>We are also finalizing as proposed that the parameters that must be used to characterize emissions should reflect operating conditions over the time period covered by the simulation rather than just over the calendar year. Under this change, reporters may continue to run the simulation once per year with parameters that are determined to be representative of operating conditions over the entire year. Alternatively, reporters will be allowed to conduct periodic simulation runs to cover portions of the calendar year, as long as the entire calendar year is covered. The reporter will then sum the results at the end of the year to determine annual emissions. In that case, the parameters for each simulation run will be determined for the operating conditions over each corresponding portion of the calendar year. We note that parameter measurements used in a previous periodic simulation within the same reporting year may be used for subsequent simulations if they are representative of that parameter under the operating conditions of the subsequent simulation. Finally, we are finalizing as proposed the clarification that the information reported under 40 CFR 98.236(d)(2)(ii) should be provided on an annual basis, either as an average across the year, or a total for the year (in the case of operating hours for the unit).</P>
                    <P>
                        We are also finalizing as proposed the replacement of the existing requirement to report solvent weight in existing 40 CFR 98.236(d)(2)(iii)(L) with a requirement in final 40 CFR 98.236(d)(2)(iii)(N) to report the solvent type and, for amine-based solvents, the general composition. Reporters must choose the solvent type option from a pre-defined list that most closely matches the solvent type and, for amine-based solvents, the general composition, used in their AGR. The standardized response options will include the following: “Selexol
                        <E T="51">TM</E>
                        ,” “Rectisol®,” “Purisol
                        <E T="51">TM</E>
                        ,” “Fluor Solvent” “Benfield
                        <E T="51">TM</E>
                        ,” “20 wt% MEA,” “30 wt% MEA,” “40 wt% MDEA,” “50 wt% MDEA,” and “Other (specify).” In the event that reporters use more than one type of solvent in their AGR during the year, as proposed, the final reporting requirement specifies for reporters to select the option that corresponds to the solvent used for the majority of the year. The EPA expects that this final amendment to collect standardized information about the solvent will result in more useful data that will improve verification of reported data and better characterize AGR vent emissions, consistent with section II.C. of this preamble. It will also improve the quality of the data reported compared to the apparently inconsistent application of the current requirements by reporters.
                    </P>
                    <HD SOURCE="HD3">3. Reporting of Flow Rates</HD>
                    <P>
                        The EPA is finalizing several revisions related to Calculation Method 4 for acid gas removal units as described in this section. The EPA received only supportive comments regarding the revisions to flow rate reporting for acid gas removal units. See the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
                    </P>
                    <P>
                        We are finalizing as proposed several amendments to improve the quality and verification of AGR flow rate information, consistent with section II.C. of this preamble. Reporters are currently required to report the total feed rate entering the AGR in units of million cubic feet per year (existing 40 CFR 98.236(d)(1)(iii), proposed 40 CFR 98.236(d)(1)(iv)). The existing rule does not specify million standard cubic feet per year or million actual cubic feet per year, so reporters may provide this feed rate in either of those units of measure. Therefore, we are first finalizing the proposal to require that the total annual feed rate that is required to be reported for all AGRs regardless of the how the emissions are calculated (existing 40 CFR 98.236(d)(1)(iii), amended 40 CFR 98.236(d)(1)(iv)) must be reported at standard conditions (
                        <E T="03">i.e.,</E>
                         in units of MMscf per year). Second, we are finalizing as proposed the requirement to report the temperature and pressure that correspond to the flow rates reported for Calculation Methods 1, 2, or 3 (reporters using Calculation Method 4 are already required to report the temperature and pressure of the acid gas feed, under existing 40 CFR 98.236(d)(2)(iii)(B) and (C)). The additions, at 40 CFR 98.236(d)(2)(i)(D) and (E) and (d)(2)(ii)(I), (J), (L), and (M), specify that reported temperature and pressure must be the actual temperature and pressure if the flow rate is reported in actual conditions, or standard temperature and pressure if the flow rate is reported in standard conditions. The EPA received only supportive comments on these additions.
                    </P>
                    <HD SOURCE="HD2">G. Dehydrator Vents</HD>
                    <HD SOURCE="HD3">1. Selection of Appropriate Calculation Methodologies for Glycol Dehydrators</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>The EPA is finalizing revisions to the calculation methodologies for glycol dehydrators largely as proposed, except for one update from proposal after consideration of comments.</P>
                    <P>
                        We are finalizing as proposed the revised calculation requirements of 40 CFR 98.233(e) to allow reporters the ability to use Calculation Method 1 or Calculation Method 2 when determining emissions from dehydrators that have an annual average of daily natural gas throughput that is less than 0.4 MMscf per day. After consideration of comments, we are finalizing the conditions under which a facility is required to use 40 CFR 98.233(e) with a modification. The proposed requirement stated that if reporters conduct modeling for environmental compliance or reporting purposes, including but not limited to compliance with Federal or state regulations, air permit requirements, or annual inventory reporting, or internal review, they would use those results for reporting under subpart W. Based on consideration of public comment concerning the nature of modeling for internal review purposes by facilities, and differences in program requirements, we are not finalizing the proposed requirement to use the results from such modeling for reporting under subpart W. We are instead requiring in the final provisions that if a facility is required to use a software program for compliance with federal or state regulations, air permit requirements or annual emissions inventory reporting that meets the requirements of 40 CFR 98.233(e)(1), they must use 40 CFR 98.233(e)(1) for reporting under subpart W. We anticipate that modeling consistent with the methodology outlined in 40 CFR 98.233(e)(1) could be conducted by reporters for environmental compliance or reporting purposes or reporters may run a simulation solely for the purpose of reporting under subpart W. This will ensure that the facility is able to use modeling results that are representative of actual operating conditions and meet the requirements of 40 CFR 98.233(e)(1) without requiring that models completed for other purposes meet the requirements under this subpart. As noted in the preamble to the proposed rule, we expect that these revisions will improve the quality of the data collected. For this reason and consistent with section II.B. of this preamble, we 
                        <PRTPAGE P="42121"/>
                        are requiring that facilities that are already completing modeling for other required reporting must use modeling to report to subpart W. The EPA is also finalizing as proposed the revisions to 40 CFR 98.236(e) to specify the applicable reporting requirements based on the selected calculation method rather than the throughput of the dehydrator. This amendment will improve the quality of the data collected, consistent with section II.B. of this preamble.
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed selection of calculation methodologies for glycol dehydrators.</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter reported that simulations are run for “internal review” for a variety of purposes, including “what-if” scenarios (
                        <E T="03">i.e.,</E>
                         exploring possible engineering adjustments), and may not meet the EPA's goal of estimating emissions based on operating conditions. The commenter recommended that only simulations run for compliance purposes should be used.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We agree with the commenter that simulations run for other purposes may not result in emissions estimations based on representative operating conditions, as facilities may complete models for a variety of purposes, including models to consider future adjustments to the operation of the unit that are based on possible future, not actual, operating conditions. We are not finalizing the proposed requirement that all results from simulations run for the purposes of “internal review” or modeling completed for environmental compliance or reporting purposes are required to be used for reporting. We are instead requiring in the final provisions that if a facility performs emissions modeling of a glycol dehydrator for compliance with federal or state regulations, air permit requirements or annual emissions inventory reporting using a software program that meets the requirements of 40 CFR 98.233(e)(1), they must also use 40 CFR 98.233(e)(1) for reporting under subpart W. We expect that these amendments as finalized will increase the quality of data collected without requiring the inclusion of results from inappropriate modeling runs. We have revised the language in 40 CFR 98.233(e) introductory text to clarify these requirements.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter requested clarification on whether reporters are compelled to use the simulation(s) from other compliance programs that may have different requirements, or if reporters can (or must) run a new simulation with an analysis pulled during the reporting year.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We are not finalizing the proposed requirement to use all the results from modeling, that may have been performed for programs with different requirements, for reporting under subpart W. We are instead requiring in the final provisions that if a facility performs emissions modeling of a glycol dehydrator for compliance with federal or state regulations, air permit requirements or annual emissions inventory reporting using a software program that meets the requirements of 40 CFR 98.233(e)(1), they must also use 40 CFR 98.233(e)(1) for reporting under subpart W. We anticipate that modeling consistent with the methodology outlined in 40 CFR 98.233(e)(1) could be conducted by reporters for environmental compliance or reporting purposes, or reporters may run a simulation for the purpose of reporting under subpart W. We have revised the language in 40 CFR 98.233(e) introductory text to clarify these requirements.
                    </P>
                    <HD SOURCE="HD3">2. Controlled Dehydrators</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>The EPA is finalizing revisions to controlled dehydrator requirements largely as proposed, except for two clarifications from proposal in the final provisions after consideration of comments.</P>
                    <P>We are finalizing as proposed revisions to the methodologies for calculating emissions from dehydrator vents controlled by a vapor recovery system, flare, or regenerator firebox/fire tubes currently provided in 40 CFR 98.233(e)(5) and (6), respectively. The new language in 40 CFR 98.233(e)(4) provides a methodology for calculating emissions vented directly to the atmosphere during periods of time when emissions are not routed to the vapor recovery system, flare, or regenerator firebox/fire tubes. For flared dehydrator emissions, the 40 CFR 98.233(e) provisions direct reporters to the methodologies in 40 CFR 98.233(n). As a regenerator firebox/fire tubes does not meet the definition of a flare per 40 CFR 98.238, we are finalizing methodologies as proposed for calculating combusted emissions from a regenerator firebox/fire tubes in 40 CFR 98.233(e)(5) using the combustion source equations W-39A, W-39B, and W-40 of 40 CFR 98.233(z)(3). We are also finalizing as proposed new reporting requirements for dehydrator units with emissions routed to a firebox/fire tubes in 40 CFR 98.236(e)(1)(xvi) and (xvii), (e)(2)(v), and (e)(3)(vii) that are consistent with the reporting requirements for combustion sources in 40 CFR 98.236(z)(2). By finalizing these amendments, the EPA enhances the overall quality of the data collected under the GHGRP, consistent with sections II.B. and II.D. of this preamble.</P>
                    <P>The EPA is also finalizing revisions as proposed to two terms consistent with the amendments for reporting for glycol dehydrators with an annual average daily natural gas throughput greater than or equal to 0.4 MMscf per day. The EPA is finalizing the definition of “dehydrator vent emissions” in 40 CFR 98.6 to confirm that dehydrator emissions reporting should include emissions from both the dehydrator still vent, and if applicable, the dehydrator flash vent. We are also finalizing as proposed the removal of the term “reboiler” from the definition of “dehydrator vent emissions”, as the term “regenerator” refers to the same piece of equipment. Finally, we are finalizing expansion of the dehydrator control types referenced in the definition of “dehydrator vent emissions” to include regenerator fireboxes/fire tubes and vapor recovery systems. Additionally, the EPA is finalizing the amended definition of “vapor recovery system” in 40 CFR 98.6 to clarify that routing emissions from a dehydrator regenerator still vent or flash tank separator vent to the regenerator firebox/fire tubes does not qualify as vapor recovery for purposes of 40 CFR 98.233. Based on consideration of commenter feedback, the EPA is also finalizing two clarifications from proposal in the final provisions. We are amending from proposal the final text in 40 CFR 98.233(e)(4)(i) to clarify that reporters must calculate the emissions that would potentially be emitted if the vapor recovery system, flare, or regenerator firebox/fire tubes was not present as a first step. We are also finalizing an amendment to make the language in 40 CFR 98.233(e) introductory text consistent with the final requirements in 40 CFR 98.233(e)(4). In finalizing these edits, the EPA will improve the quality of the emissions data reported and confirm the original intent of these terms.</P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to the reporting requirements for controlled dehydrators.</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter requested the removal of the requirement in 40 
                        <PRTPAGE P="42122"/>
                        CFR 98.233(e)(4)(i) to calculate the “maximum potential annual vented emissions.” The commenter noted that the requirement conflicts with the requirements that simulations should “represent the operating conditions.” The commenter noted that determining a maximum potential case requires assuming worst-case conditions, which does not reflect actual operations and does not further the EPA's goal of accurately determining emissions.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA agrees with the commenter that emissions need to be determined based on operating conditions. The intent was not for reporters to calculate the emissions that the dehydrator has the potential to emit based on worst-case conditions; the intention was for reporters to calculate the emissions that would potentially be emitted if the vapor recovery system, flare, or regenerator firebox/fire tubes was not present, as the first step in the process of calculating emissions that are vented directly to the atmosphere during periods of time when emissions are not routed to that device. The EPA has amended text from proposal in final 40 CFR 98.233(e)(4)(i) to clarify this intent.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter noted that the 40 CFR 98.233(e) introductory text implies that uncontrolled emissions are calculated and then adjusted downward. The commenter stated that proposed 40 CFR 98.233(e)(4) directs reporters to calculate only those proposed emissions directly vented to the atmosphere. The commenter recommended that the EPA revise the 40 CFR 98.233(e) introductory text to remove the reference to adjusting emissions downward.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA agrees with the commenter that the reporter must calculate only emissions directly vented to the atmosphere. The language in 40 CFR 98.233(e) introductory text is consistent with the current requirements in 40 CFR 98.233(e)(5) for dehydrators with vapor recovery, but it was inadvertently not adjusted in the proposal to match the proposed requirements in 40 CFR 98.233(e)(4). The EPA is finalizing an amendment to the language in 40 CFR 98.233(e) introductory text consistent with the final requirements in 40 CFR 98.233(e)(4).
                    </P>
                    <HD SOURCE="HD3">3. Calculation Method 1 for Glycol Dehydrators</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>The EPA is finalizing revisions to the Calculation Method 1 for glycol dehydrators largely as proposed, except for three clarifications and updates from proposal after consideration of comment.</P>
                    <P>
                        We are finalizing that reporters would collect measurements of the simulation input parameters listed under 40 CFR 98.233(e)(1) consistent with section II.B. of this preamble, with one change from the proposal The final parameters required to be measured include feed natural gas water content, wet natural gas temperature and pressure at the absorber inlet, and wet natural gas composition. The proposal also included a requirement to measure feed natural gas flow rate. However, after consideration of comments received, in an effort to reduce burden on reporters, we are not finalizing the requirement to directly measure feed natural gas flow rate; instead, we are requiring that feed natural gas flow rate must be determined based on measured data. For example, facilities may determine the feed natural gas flow rate based on measured outlet natural gas flow; we expect that this method determining feed natural gas flow rate to be accurate and less burdensome for facilities by using existing instrumentation. Requirements for measurement frequency for 40 CFR 98.233(e)(1)(i), (ii), (x) and (xi) are being finalized as proposed; for these input parameters, where parameters are determined to be representative of operating conditions over the entire year, the measurements must be taken at least once per year or where the measurements are only reflective of representative operating conditions over shorter time periods the measurements must be taken multiple times per year. However, given the significant burden noted by commenters to sample composition each reporting year, the EPA is finalizing a reduced frequency schedule for composition sampling and analysis (40 CFR 98.233(e)(1)(xi)). Reporters must sample and analyze composition at least once every five years. We are clarifying in the final rule that if physical or operational changes are made such that the measured sample is no longer representative of operating conditions, reporters must collect a new sample and re-analyze composition. We are requiring that samples must be collected within six months of the startup of production or by January 1, 2030 (
                        <E T="03">i.e.,</E>
                         within five years of the effective date of the rule), whichever date is later and at least once every five years thereafter. Until such time that a sample can be collected, reporters may continue to determine these parameters by using one of the existing methods. We believe that samples taken at this frequency will be sufficiently representative as we do not expect significant changes except in cases where physical or operational changes, (
                        <E T="03">e.g.,</E>
                         increased TEG circulation rate) are made.
                    </P>
                    <P>We are also finalizing as proposed that the parameters that must be used to characterize emissions should reflect operating conditions over the time period covered by the simulation rather than just over the calendar year. Under this change, reporters could continue to run the simulation once per year with parameters that are determined to be representative of operating conditions over the entire year. Alternatively, reporters would be allowed to conduct periodic simulation runs to cover portions of the calendar year, as long as the entire calendar year is covered. The reporter will then sum the results at the end of the year to determine annual emissions. In that case, the parameters for each simulation run will be determined for the operating conditions over each corresponding portion of the calendar year. In the case of more than one simulation covering the reporting period, the reported parameter is the average of the parameters for each simulation. Finally, we are finalizing a clarification that the information reported under 40 CFR 98.236(e)(1) should be provided on an annual basis, either as a total for the year (in the case of operating hours for the unit and emissions) or as an average across the year (for all other input parameters).</P>
                    <P>We are finalizing as proposed the addition of ProMax as an example software program for calculating dehydrator emissions per 40 CFR 98.233(e)(1) for clarity for reporters. Consistent with the EPA's approval of ProMax for NESHAP HH compliance, the EPA is finalizing as proposed the requirement that if reporters elect to use ProMax, they will be required to use version 5.0 or above.</P>
                    <P>In order to assess potential emissions changes between reporting years, the EPA is also finalizing the addition of a new provision under 40 CFR 98.236(e)(1)(xviii) to request reporting of the modeling software used to calculate emissions for each dehydrator unit using Calculation Method 1. These amendments will improve the quality of the data collected, consistent with section II.B. of this preamble.</P>
                    <P>
                        The EPA is finalizing as proposed under 40 CFR 98.236(e) the requirement to separate reporting of emissions for a modeled glycol dehydrator's still vent and flash tank vent. These amendments will improve the quality of the data collected, consistent with section II.C. of this preamble.
                        <PRTPAGE P="42123"/>
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the Calculation Method 1 for glycol dehydrators.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Two commenters noted that the proposed requirement to measure feed natural gas flow rate is impractical, would require significant investment, and does not increase data quality. The commenters noted that facilities are not equipped with meters upstream of the dehydration unit, but gas flow is measured at the unit outlet. The commenters recommend that feed natural gas flow rate be determined based on measured data.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         After further consideration, the EPA is not finalizing the proposed requirement to measure the feed natural gas flow rate as our assessment is that there are other measurements that could be used to determine the feed natural gas flow rate that would have similar data quality. The EPA is instead requiring that reporters determine the feed natural gas flow rate based on measured data, which could include facility discharge meters or wellhead meters. Our assessment is that this will allow the use of existing instrumentation and also decrease burden, while maintaining data quality.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter requested clarification on the proposed measurement frequency of model input parameters. The commenter also requested that even for multiple simulations a re-collection of parameters only be required upon suspected changes. The commenter noted that an operator can conduct one simulation on an annual basis using one set of parameters collected by the operator. Additionally, an operator may conduct periodic simulations. The commenter stated that conducting periodic simulations assists an operator in ensuring that it fully complies with the regulations in a timely manner that allows for any potential errors to be addressed in subsequent simulations. The commenter stated that the EPA disincentives periodic simulations by requiring an operator to perform field measurements to establish the parameters for every simulation.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We are clarifying in the final rule that the frequency of measurement for the input parameters at for 40 CFR 98.233(e)(1)(i), (ii) and (x) must be measured at least once per year, but the measurement may be used in simulations covering different portions of the calendar year if the measurement is reflective of operating conditions over the time period of the simulation. After consideration of comment, the EPA is also finalizing a reduced frequency schedule from that proposed for the measurement of composition. Reporters must sample and analyze composition at least once every 5 years. Additionally, input parameters must be remeasured if no longer representative of operating conditions; for example, if physical or operational changes are made that may result in an increase in CH
                        <E T="52">4</E>
                         or CO
                        <E T="52">2</E>
                         emissions, reporters must collect and analyze a new sample. After consideration of the burden noted by commenters to collect samples within one year of finalization of the rule, the EPA is allowing 5 years from the date of publication of this final rule, or within 6 months of the startup of production, whichever date is later, for reporters to collect a composition sample. Until a sample is collected, facilities may use the existing methods. We believe that measurements taken at this frequency will be sufficiently representative of operating conditions as we do not expect significant changes except in cases where physical or operational changes (
                        <E T="03">e.g.,</E>
                         increased TEG circulation rate) are made.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter requested clarification on the reporting requirements for the inputs to the simulation. The commenter noted that 40 CFR 98.233(e)(1) requires reporters to “collect measurements reflective of representative operating conditions for the time period covered by the simulation” but 40 CFR 98.236(e)(1) requires reporting as an “annual average.” The commenter noted that “annual average” implies a different standard than “measurements reflective of representative operating conditions.”
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA agrees with the commenter that the reporter must collect measurements reflective of representative operating conditions. The EPA updated the final 40 CFR 98.236(e)(1) to clarify that in the case of more than one simulation covering the reporting period, the data reported is to be either the total (in the case of operating hours or emissions) and the average of the inputs to each simulation for all other input parameters.
                    </P>
                    <HD SOURCE="HD3">4. Calculation Method 2 for Glycol Dehydrators</HD>
                    <P>
                        The EPA is finalizing revisions to the Calculation Method 2 reporting requirements for glycol dehydrators as proposed. The EPA received only supportive comments regarding the revisions to Calculation Method 2 for glycol dehydrators. See the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
                    </P>
                    <P>
                        Specifically, the EPA is finalizing as proposed the clarification in 40 CFR 98.233(e)(2) that the dehydrators for which emissions are calculated should be those with annual average daily natural gas throughput greater than 0 MMscf per day and less than 0.4 MMscf per day (
                        <E T="03">i.e.,</E>
                         the count should not include dehydrators that did not operate during the year). Similarly, the EPA is finalizing as proposed clarification in 40 CFR 98.236(e)(2) introductory text that the count of dehydrators in existing 40 CFR 98.236(e)(2)(i) (amended 40 CFR 98.236(e)(2)(ii)) should also be those with annual average daily natural gas throughput greater than 0 MMscf per day and less than 0.4 MMscf per day. These amendments will improve implementation and verification of reported data, consistent with section III.C. of this preamble.
                    </P>
                    <P>
                        The EPA is finalizing as proposed revisions to the data collected under current 40 CFR 98.236(e)(2)(iii) (amended 40 CFR 98.236(e)(2)(iv)) to emphasize the original intent of the rule. We are finalizing as proposed the requirement to specifically state that the reporting of “other” control devices should only include control devices that reduce CO
                        <E T="52">2</E>
                         and/or CH
                        <E T="52">4</E>
                         emissions. This final revision will allow the EPA to verify the expected reductions in vented CO
                        <E T="52">2</E>
                         and/or CH
                        <E T="52">4</E>
                         emissions due to the use of the control device. This final amendment will improve implementation and verification of reported data, consistent with section III.C. of this preamble.
                    </P>
                    <HD SOURCE="HD3">5. Desiccant Dehydrators</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>The EPA is finalizing revisions to the reporting requirements for desiccant dehydrators in 40 CFR 98.236(e) largely as proposed, except for three clarifying corrections and updates from proposal after consideration of comment. The EPA also is finalizing related changes to definitions of “dehydrator” and “desiccant” in 40 CFR 98.6 as proposed.</P>
                    <P>
                        Specifically, we are finalizing removal of the cross-references from 40 CFR 98.236(e)(3) to 40 CFR 98.236(e)(2)(i) through (iv) and instead are including all of the applicable reporting requirements from current 40 CFR 98.236(e)(2)(i) through (iv) for desiccant dehydrators under 40 CFR 98.236(e)(3). Replicating the requirements under 40 CFR 98.236(e)(3) will make the rule easier to follow and allow the EPA to 
                        <PRTPAGE P="42124"/>
                        further clarify the required reporting data elements for desiccant dehydrators. One clarifying correction that is being finalized consistent with public comment is removal of the proposed reference to flash tanks in 40 CFR 98.236(e)(3)(vii)(B), which was referenced in error. A second clarifying correction that is being finalized consistent with public comment is all proposed references to regenerator firebox/fire tubes in 40 CFR 98.236(e)(3) have been replaced with references to non-flare combustion units as commenters noted that desiccant dehydrators are not known to have configurations with regenerator firebox/fire tubes. The final rule also includes conforming changes in 40 CFR 98.233(e)(5) to specify procedures for calculating emissions from non-flare combustion units used with desiccant dehydrators that are the same as the procedures for calculating emissions from regenerator fireboxes/fire tubes that are used with small glycol dehydrators.
                    </P>
                    <P>
                        The EPA also is finalizing as proposed the addition of four new desiccant dehydrator reporting data elements in 40 CFR 98.236(e)(3), we are not finalizing one proposed reporting element, and we are finalizing as proposed the removal of reporting the total count of desiccant dehydrators at the facility as required in 40 CFR 98.236(e)(3)(i) of the existing rule. The four new data elements are the total volume of all opened desiccant dehydrator vessels in 40 CFR 98.236(e)(3)(iii), the total number of desiccant dehydrator openings in the calendar year in 40 CFR 98.236(e)(3)(iv), the count of opened desiccant dehydrators that used deliquescing desiccant (
                        <E T="03">e.g.,</E>
                         calcium chloride or lithium chloride) in 40 CFR 98.236(e)(3)(ii)(A) (proposed 40 CFR 98.236(e)(3)(ii)(B)), and the count of opened desiccant dehydrators that used regenerative desiccant (
                        <E T="03">e.g.,</E>
                         molecular sieves, activated alumina, or silica gel) in 40 CFR 98.236(e)(3)(ii)(B) (proposed 40 CFR 98.236(e)(3)(ii)(C)). The proposal also included a requirement to report the total count of opened desiccant dehydrators in 40 CFR 98.236(e)(3)(ii)(A). However, to eliminate duplicative reporting requirements, we are not finalizing the requirement to report the total count of opened desiccant dehydrators, as we will have the information through the sum of the opened dehydrators using deliquescing desiccant and the opened dehydrators using regenerative desiccant. After removing the data element for the total count of opened desiccant dehydrators, the two new reporting data elements for the count of opened desiccant dehydrators that used deliquescing desiccant and the count of opened desiccant dehydrators that used regenerative desiccant have been moved to 40 CFR 98.236(e)(3)(ii)(A) and (B) in the final amendments. These amendments will improve verification of reported data and ensure accurate reporting of emissions, consistent with section II.C. of this preamble.
                    </P>
                    <P>The EPA is also finalizing revisions to the definitions of “dehydrator” and “desiccant” in 40 CFR 98.6 as proposed. In the definition of “dehydrator,” we are finalizing the change to replace the word “absorb” with “remove,” and we are finalizing the change to clarify that desiccant is not a type of liquid absorbent. In the definition of “desiccant” we are finalizing the change to include “molecular sieves” in the list of example desiccants and we are finalizing the change to clarify that desiccants include, “but are not limited to,” molecular sieves, activated alumina, pelletized calcium chloride, lithium chloride and granular silica gel material. We expect these amendments will improve the overall quality and completeness of the emissions data collected by the GHGRP, consistent with section II.A. of this preamble.</P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses on Desiccant Dehydrators</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to reporting requirements for desiccant dehydrators.</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter noted that references to “regenerator firebox/fire tubes” throughout the desiccant dehydrator reporting requirements in 40 CFR 98.236(e)(3) appear to be a mistake because the commenter is not aware of desiccant dehydrators that route emissions to regenerator firebox/fire tubes. The commenter suggested that references to non-flare combustion calculations may be more appropriate. The commenter also noted that 40 CFR 98.236(e)(3)(vii)(B) should be changed to remove the reference to flash tanks because flash tanks are used only with glycol dehydrators, not desiccant dehydrators.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We agree with the commenter that regenerator firebox/fire tubes are not used with desiccant dehydrators. Regenerator firebox/fire tubes are used with glycol dehydrators to provide the energy needed to drive water out of rich glycol to produce lean glycol for recirculation to the absorber, but they are not needed in the operation of desiccant dehydrators. The current rule requires reporting of combusted emissions from dehydrator emission streams that are routed to a flare or regenerator firebox/fire tubes. Since regenerator firebox/firetubes are not needed for operation of desiccant dehydrators, it is possible that all combustion emissions reported for desiccant dehydrators under subpart W are from flares. However, to allow for the possibility that some emissions from desiccant dehydrators may be routed to a regenerator firebox/fire tubes for a glycol dehydrator at the same site, and to allow reporting of combusted emissions from thermal oxidizers or other types of combustion devices, we are replacing the proposed references to regenerator firebox/firetubes in 40 CFR 98.236(e)(3) in the final rule provision with references to “non-flare combustion unit.” This change will allow complete and accurate reporting of all combusted emissions from desiccant dehydrators.
                    </P>
                    <P>We also agree with the commenter that the proposed reference to flash tanks in the desiccant dehydrator reporting requirements is incorrect. Flash tanks reduce the pressure of the rich glycol stream out of the absorber for a glycol dehydrator, thereby separating a significant portion of the high vapor pressure compounds, such as methane, from the liquid glycol upstream of the regenerator; flash tanks are not applicable for desiccant dehydrators. Thus, after considering both this comment and the one above, the reporting requirement in 40 CFR 98.236(e)(3)(vii)(B) of the final rule was changed from proposal to read as follows: “Total volume of gas routed to non-flare combustion units, in standard cubic feet.”</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter stated that the EPA should eliminate reporting elements that are duplicative of other data it is already collecting and that simply add steps to reporters without any additional information to be gained. As an example, the commenter cited the proposed requirement in 40 CFR 98.236(e)(3)(ii)(A) to report the total number of opened desiccant dehydrators, which should be equal to the sum of the total number of opened desiccant dehydrators that used deliquescing desiccant in proposed 40 CFR 98.236(e)(3)(ii)(B) plus the total number of opened desiccant dehydrators that used regenerative desiccant in proposed 40 CFR 98.236(e)(3)(ii)(C).
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         After consideration of public comment to eliminate duplicative reporting requirements, we are not finalizing the proposed requirement to report the total count of opened desiccant dehydrators because 
                        <PRTPAGE P="42125"/>
                        this quantity can be calculated as the sum of the reported count of opened dehydrators using deliquescing desiccant plus the reported count of opened dehydrators using regenerative desiccant and is, therefore, redundant.
                    </P>
                    <HD SOURCE="HD2">H. Liquids Unloading</HD>
                    <HD SOURCE="HD3">1. Summary of Final Amendments</HD>
                    <P>The EPA is finalizing several changes to calculation methods and the reporting requirements for liquids unloading. These changes are expected to improve data quality while recognizing the operational challenges that facility operators can face in the field when managing unloading events, including monitoring and measuring emissions from those events.</P>
                    <P>Consistent with section II.C. of this preamble, we are clarifying the proposal that required reporters to calculate and report emissions when natural gas emissions from well venting for liquids unloading are routed to the atmosphere or to a control device, recognizing that some reporters may choose to flare or use natural gas at the well-pad. In the final rule, we are narrowing this to require reporting of liquids unloading emissions when natural gas is vented to the atmosphere or to a flare because use in other combustion equipment on-site will be captured by the combustion source. We have expanded, as proposed, the type of unloading from just plunger lift or non-plunger lift unloadings to also include a designation of whether each unloading event is a manual or automated unloading. Therefore, there are now four unloading types: automated plunger lift, manual plunger lift, automated non-plunger lift and manual non-plunger lift. The EPA proposed and is finalizing this requirement to more accurately characterize emissions from liquids unloading. In addition to changes to 40 CFR 98.233(f) and 98.236(f), we are finalizing as proposed definitions in 40 CFR 98.238 for “Manual liquids unloading” and “Automated liquids unloading.”</P>
                    <P>
                        The EPA is finalizing further clarifying changes to liquids unloading calculation methods in 40 CFR 98.233(f)(2) after consideration of public comment to more accurately calculate emissions from liquids unloading. For Calculation Method 2, the definition of CD
                        <E T="52">p</E>
                        , casing diameter, is amended in the final rule to clarify that CD
                        <E T="52">p</E>
                         can also include the tubing diameter when stoppage packers have been placed downhole in the annulus, forcing unloadings to travel to the surface through the tubing string rather than the annulus. The definition of WDp, well depth, for Calculation Method 2 is also amended in the final rule to clarify that well depth may be measured from either the bottom of the well or the top of the fluid column. This has a direct bearing on the first part of equation W-8, which estimates the quantity of natural gas in the production column that will be initially emitted when the well is unloaded. Reporters are not required to determine the top of the fluid column, but allowing reporters to have the option to define the top of the liquid column and establish that depth as the bottom of the well recognizes that the available capacity in the wellbore to hold accumulated gas volumes is displaced by liquids and results in more accurate emissions measurements. Although some natural gas may be entrained in the liquid column, the volume of gas is likely to be very small compared to volume of gas in the borehole above the liquid column. Additionally, liquids from the unloading are expected to be directed to an atmospheric tank or separator where gas emissions from gas entrained in the liquids will be reported in the tanks source under 40 CFR 98.233(j). If the reporter is unable to determine the top of the fluid column or chooses not to do so, the reporter must assume that well depth is the bottom of the well. We are finalizing a similar clarifying change to the definition of well depth in the calculation requirements for Calculation Method 3 for the same reasons.
                    </P>
                    <P>For well depth in Calculation Method 2, we are also finalizing a clarification in defining the bottom of the well for horizontal wells, to be the point at which the borehole pivots downhole from vertical to horizontal. Horizontal wells produce gas along one or more horizontal laterals directing flow from the producing formation through the cased hole to the production string at the base of the vertical portion of the well. Unloadings are required when wells, primarily gas wells, accumulate liquids in the wellbore, and velocity up the production tubing is not sufficient to lift liquids to the surface. The well is effectively shut-in and ceases production until the liquids are lifted and gas flow is restored. Horizontal laterals are perforated at varying intervals and liquids accumulation in a horizontal well will generally occur first in the horizontal portion of the well because that is where gas with entrained liquids will enter the production string. Eventually liquids will accumulate throughout the horizontal lateral to the base of the vertical section of the well or even closure to the surface. This change recognizes that it is very likely that a horizontal well requiring an unloading will have liquids accumulation from the top of the fluid column at the bottom of the vertical portion of the well downhole through the extent of the horizontal portion of the well. We are, therefore, allowing reporters using Calculation Method 2 for non-plunger unloadings to consider the bottom of the well for a horizontal well to be the point at which the vertical borehole pivots to a horizontal direction. This change only affects Calculation Method 2. The bottom of the well in Calculation Method 3 is defined as tubing depth to the plunger bumper, which is generally at the bottom of the vertical portion of a well.</P>
                    <P>
                        We are also finalizing amendments in 40 CFR 98.233(f) and 98.236(f) that recognize that some reporters may direct natural gas emissions from liquids unloading to flare stacks. Prior to this rulemaking, natural gas emissions from unloadings were assumed to be from venting the unloadings. Based on review of public comment submitted to the EPA in response to the proposed amendments from June 2022, we understand that some reporters may be considering directing emissions to a flare stack or other control device. Therefore, in the proposal for this rulemaking, we included regulatory text to require reporting of emissions and other data if natural gas flow from a liquids unloading is directed to a flare or control device. We are finalizing provisions in 40 CFR 98.233(f) directing reporters to use the calculation methods in 40 CFR 98.233(n) for flare stacks to calculate associated unloading emissions from flaring and report these emissions under 40 CFR 98.236(n). If natural gas from unloadings is directed to other control devices, the emissions should be calculated as part of that source (
                        <E T="03">e.g.,</E>
                         through the combustion source type) under the 40 CFR 98.233 provisions for those source types.
                    </P>
                    <P>
                        With respect to Calculation Method 1, the EPA proposed to require use of this method to calculate emissions for each well at least once every 3 years. Calculation Method 1 requires that a reporter record an average flow rate at a representative well by placing a recording flow meter on the vent line from the well to an atmospheric tank, separator or other device to vent the gas. The flow rate may be applied to other wells in the same sub-basin/unloading type/pressure-diameter combination. Therefore, the EPA's proposal would have required reporters to measure a representative well in each sub-basin at least once every 3 years. We received many comments suggesting the requirement was overly burdensome 
                        <PRTPAGE P="42126"/>
                        and unrealistic given the operational, logistical, and technical challenges of placing flow meters on the vent lines to so many wells. Unloadings are not steady state events, and the variability of flow in an unloading event can also impact the accuracy of measurement using a single flow meter as there will often be a large expulsion of gas at the initiation of the unloading followed by a quickly declining emission rate until gas begins flowing again to the sales line or other flow line. After consideration of public comment and given the challenges with flow measurement discussed above, the EPA is not finalizing the proposed requirement to use Calculation Method 1 to measure a representative well in each sub-basin at least once every 3 years in this final rule. Instead, the EPA is retaining the existing requirement that allows reporters to choose Calculation Method 1 as an option over the engineering equations in Calculation Methods 2 and 3. In doing so we encourage reporters to use measured data in Calculation Method 1 where feasible. However, we are confident that use of the engineering equations in Calculation Methods 2 and 3 provides accurate estimates of emissions from unloadings because inputs to the equations are based on well-specific empirical data including casing and tubing diameter, well depth, shut-in or line pressure, the flow line rate of gas, and the time the well is left open for venting. Furthermore, the additional granularity of reported data including all data inputs to the equations and disaggregated reporting at the well level will allow for more thorough verification by the EPA of reported data.
                    </P>
                    <P>Although the final rule does not require use of Calculation Method 1 at least once every three years, the rule retains the existing requirement that reporters electing to use Calculation Method 1 must calculate a new average flow rate every other calendar year starting with the first calendar year of data collection.</P>
                    <P>
                        The EPA is also finalizing as proposed revisions to 40 CFR 98.236(f)(1) and (2) to require the reporting of certain data elements that are included in existing equations W-8 and W-9 for Calculation Methods 2 and 3 when calculating emissions from unloadings but which were previously not reported. For Calculation Method 2, for wells without plunger lifts, reporting of the following additional data elements will now be required: well depth (WD
                        <E T="52">p</E>
                        ), the average flow-line rate of gas (SFR
                        <E T="52">p</E>
                        ), the hours that wells are left open to the atmosphere during unloading events (HR
                        <E T="52">p,q</E>
                        ), and the shut-in, surface or casing pressure (SP
                        <E T="52">p</E>
                        ). For Calculation Method 3, required reporting for wells with plunger lifts will now include the additional following data elements: tubing depth (WD
                        <E T="52">p</E>
                        ), the flow-line pressure (SP
                        <E T="52">p</E>
                        ), the average flow-line rate of gas (SFR
                        <E T="52">p</E>
                        ), and (HR
                        <E T="52">p,q</E>
                        ). Requiring reporting of these data elements will improve verification of annual reports to the GHGRP and will allow the EPA and the public to replicate calculations and more confidently confirm reported emissions than is currently possible.
                    </P>
                    <HD SOURCE="HD3">2. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to liquids unloading.</P>
                    <P>
                        <E T="03">Comment:</E>
                         The EPA received comments asserting that the proposed rule language that requires Calculation Method 1 every 3 years is unnecessary and burdensome and will not lead to more accurate reporting. Commenters also requested that the EPA allow an operator that uses direct measurement in the first year to use the data obtained from that first-year direct measurement in calculating emissions in subsequent years (
                        <E T="03">i.e.,</E>
                         years 2 and 3). One commenter further asserted that the EPA did not consider the Allen et al. (2015) study that directly measured emissions from liquids unloading.
                        <SU>51</SU>
                        <FTREF/>
                         Commenters stated that knowing which wells will require and how often they require liquids unloading venting is not predictable or consistent. Commenters stated that when unloadings are needed is variable and does not necessarily occur every 3 years. Commenters also suggested that placement of a flow meter on the vent line will result in unacceptable back-pressure on the well, effectively defeating the purpose of an unloading, which is to relieve back pressure on the well. One commenter also noted that the EPA does not require operators under NSPS OOOOb to install a flow meter for liquids unloading venting. One commenter provided anecdotal evidence from an operator, based on placement of flow meters at 12 wells, that doing so caused significant operational problems at the wells. Commenters requested that the EPA instead continue to allow use of the engineering equations in Calculation Methods 2 and 3, remove the proposed requirement to use Calculation Method 1 every 3 years, and retain Calculation Method 1 as an option for calculating emissions from liquids unloading.
                    </P>
                    <FTNT>
                        <P>
                            <SU>51</SU>
                             Allen, D.T., 
                            <E T="03">et al.,</E>
                             2015. “Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States: Liquid Unloadings.” 
                            <E T="03">Eviron. Sci. Technol.</E>
                             49, 641-648. 
                            <E T="03">https://pubs.acs.org/doi/10.1021/es504016r.</E>
                             Available in the docket for this rulemaking, Docket ID. No. EPA-EQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        <E T="03">Response:</E>
                         The EPA acknowledges that there can be challenges associated with installing, operating, and monitoring flow meters on well-pads. Liquid unloadings are not typically steady state events. Back pressure on the vent line could result from use of orifice flow meters with orifice cross-sections that are unable to manage highly variable flow rates, especially following an initial surge of liquids from the early stage of unloading. Back pressure can be alleviated by changing out the orifice plates. However, we acknowledge that this can be technically challenging in cases where unloading events are subject to highly variable flow rates and/or in cases when the occurrence of unloading events is not predictable. The EPA does note that Allen et. Al. in their 2015 study on liquids unloading, placed flow meters on the vent lines to tanks and did not report any back pressure or impediments to the vent line.
                    </P>
                    <P>We agree with the commenters that robust engineering equations for liquids unloadings can provide reasonable estimates of emissions if all unloading events are recorded accurately and all inputs to engineering equations are recorded and reported accurately. In addition, the additional new reporting requirements for unloadings in this final rule require all data elements in equations W-8 and W-9 to be reported, allowing for more thorough verification of reported emissions. Given these considerations, the EPA is not finalizing the proposed requirement to use Calculation Method 1 every 3 years. Instead, Calculation Method 1 will remain an option for reporters, who may choose between the three robust Calculation Methods under the final rule. Should a reporter elect to use Calculation Method 1, the reporter must comply with the existing requirement to calculate a new average flow rate every other calendar year starting with the first calendar year of data collection. For a new producing sub-basin category, the reporter must calculate an average flow rate beginning in the first year of production.</P>
                    <P>
                        The EPA agrees that operators are not required to install a flow meter under NSPS OOOOb; however, we note that program and this program have complimentary but not identical goals. As such, the EPA disagrees with the commenter's assertion that the lack of a requirement for flow meters under the NSPS on its own would be justification for not requiring measurement of liquids unloading events under subpart W.
                        <PRTPAGE P="42127"/>
                    </P>
                    <P>The Allen et. Al. study measured emissions from liquids at 107 wells in four producing regions in the U.S. The study noted that measured emissions at wells with plunger lift unloadings exceeded calculated emissions using equation W-9. Conversely, emissions at wells with non-plunger lift unloadings using equation W-8 were greater than emissions measured by study. The conclusion of the study was that the GHGRP nationwide total unloading emissions and the study's nationwide estimate extrapolated from the 107 wells in the study were roughly equivalent. Although the study found some variance between the results of the engineering equations used for liquids unloading in the GHGRP and the measurements taken in the field, the EPA believes the relative consistency of nationwide results confirms the adequacy of the equations. In addition, the new reporting requirements that further differentiate the type of unloading between manual and automated plunger lift and non-plunger lift unloadings and the required reporting of all data elements in equations W-8 and W-9 will result in more effective use of, and accurate results from, the engineering equations.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters supported the proposed revisions to add reporting requirements for liquids unloading events, including whether the unloading event is automatic or manual, specific flow-line and tubing depth data, and the hours that wells are left open during unloading events. However, commenters suggested that the EPA clarify that reporting for unloading events should only apply when the gas is vented directly to the atmosphere or routed to a control device to improve clarity for reporters and provide greater context for the reported emissions for the EPA. Other commenters requested clarification on what constitutes a control device.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA acknowledges the commenters' support for the new reporting requirements for liquids unloading and is finalizing those requirements largely as proposed. Additionally, the EPA agrees with the commenter's recommendation to include language that clarifies that only gas vented directly to the atmosphere or routed to a flare should be reported and is finalizing language to this effect.
                    </P>
                    <P>
                        The EPA proposed to limit the calculation and reporting of emissions to unloadings that vented directly to the atmosphere or to a control device because it is those unloadings that release greenhouse gas emissions. After further consideration, the EPA is retaining this language in the final rule but is changing the proposed “control device” reference to flares to be more specific. It is possible that some natural gas from unloading events is routed to other types of control devices, but emissions from these events will be covered under those other sources (
                        <E T="03">e.g.,</E>
                         the combustion source). Although we do not expect large volumes of natural gas to be directed to flares given the purpose, nature and duration of unloading events, there may be some instances of flaring gas off an unloading, and the EPA believes it is important to capture these emissions. The final rule in 40 CFR 98.233(f) directs reporters who flare natural gas from unloadings to calculate emissions using the calculation methods in 40 CFR 98.233(n), Flare Stacks and report those emissions under 40 CFR 98.236(n).
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         The EPA received comments recommending that it consider revising the definition of Casing Diameter (CD
                        <E T="52">p</E>
                        ) in equation W-8 to ID
                        <E T="52">p</E>
                         (Internal Diameter) to allow the application of either tubing diameter if the well is equipped with tubing string and no plunger lift, or casing diameter if the well does not have tubing and plunger lift. According to the commenter, it is common practice for operators to first install a tubing string to increase flow velocity and install a plunger lift later when the well undergoes production decline. The commenter stated that the diameter that is used in the equation should be the diameter of the portion of the well that is vented, whether venting the casing, tubing, or both. The commenter also recommended that the EPA should clarify that the well depth is based only on the vertical depth for horizontal wells. The commenter stated that the volume of liquid should not be considered gas that is vented, and rather only the depth above the fluids should be used to quantify the vented gas.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA recognizes that operators may place stoppage packers in the annulus of some wells, thereby removing the potential for gas lift in the annulus so that the gas lift occurs in the tubing string. Therefore, the EPA is amending the definition of CD
                        <E T="52">p</E>
                         in this final rule to address the use of stoppage packers. The definition of CD
                        <E T="52">p</E>
                         in the final rule states that it means, “Casing internal diameter for well, p, in inches or the tubing diameter for well, p, when stoppage packers are used in the annulus to restrict flow of gas up the annulus to the surface.” We disagree, however, with the recommendation to revise the definition of casing diameter in equation W-8 to internal diameter (ID
                        <E T="52">p</E>
                        ) because there could be gas lift in the annulus between the casing and the tubing string.
                    </P>
                    <P>The EPA also agrees with the commenter that the depth should be based on the vertical depth for horizontal wells. In most cases, the horizontal portion of the well is very likely to be filled with liquids from the end of the well bore up to at least the pivot point when the horizontal hole pivots to vertical. While we acknowledge that horizontal wells are very rarely truly horizontal through the well-bore, and there is a possibility that some small quantities of gas may exist in the non-vertical portion of the well-bore, these are likely to be limited cases. The vertical portion of the well bore is where the gas column will be mostly located. Horizontal wells produce gas along one or more horizontal laterals directing flow from the producing formation through the cased hole to the production string at the base of the vertical portion of the well. Unloadings are required when wells, primarily gas wells, accumulate liquids in the wellbore, and velocity up the production tubing is not sufficient to lift liquids to the surface; the well is effectively shut-in and ceases production until the liquids are lifted and gas flow is restored. Horizontal laterals are perforated at varying intervals along the lateral and liquids accumulation in a horizontal well will generally occur first in the horizontal portion of the well because that is where gas with entrained liquids enters the production string. Eventually liquids are likely to accumulate throughout the horizontal lateral to the base of the vertical section of the well or even closer to the surface. In the final rule, we have modified the definitions for well depth in equation W-8 to add clarifying language allowing reporters using Calculation Method 2 for non-plunger unloadings to consider the bottom of the well for a horizontal well to be the point at which the vertical borehole pivots to a horizontal direction. This change recognizes that it is very likely that a horizontal well requiring an unloading will have liquids accumulation from the top of the fluid column at the bottom of the vertical portion of the well downhole through the extent of the horizontal portion of the well. We do not believe the additional language is necessary for equation W-9. The bottom of the well in Calculation Method 3 is defined as tubing depth to the plunger bumper and the bumper will normally be at the vertical base of the well.</P>
                    <P>
                        Regarding well depth and the fluid column, the final rule allows for reporters to consider the fluid column 
                        <PRTPAGE P="42128"/>
                        depth in equations W-8 and W-9. More specifically, for wells where the fluid column extends above the bottom of the well, well depth may be measured from the top of the fluid column and this change is made in the definition of WD
                        <E T="52">p</E>
                         in equations W-8 and W-9 in the final rule. This is optional for reporters and if they do not use the top of the fluid column, they must consider the well depth to extend to the bottom of the vertical portion of the well in equation W-8 for Calculation Method 2 and to the plunger bumper in equation W-9 for Calculation Method 3. The EPA is finalizing the rule with this option because we understand that the available capacity to hold accumulated gas volumes below the top of the fluid level in the wellbore is displaced by liquids. Allowing reporters to consider the top of the fluid column to be the bottom of the well in these instances will result in more accurate emissions measurements. The EPA acknowledges that in some cases small volumes of gas may be entrained in the liquids. The entrained gas will separate from the liquids at a separator or atmospheric tank downstream of the well and the entrained gas emissions are subject to reporting in the hydrocarbon liquids and produced water storage tanks source under 40 CFR 98.233(j). The proposed definition for WD
                        <E T="52">p</E>
                         in W-8 was “Well depth from either the top of the well or the lowest packer to the bottom of the well, for well, p, in feet.” In the final rule, we have added additional clarifying language so that the final definition reads, “Well depth from either the top of the well or the lowest packer to the bottom of the well or to the top of the fluid column, for well, p, in feet. For horizontal wells the bottom of the well is the point at which the vertical borehole pivots to a horizontal direction.” In equation W-9, the definition for well depth, WD
                        <E T="52">p</E>
                        , in the final rule is “Tubing depth to plunger bumper or to the top of the fluid column for well, p, in feet.”
                    </P>
                    <HD SOURCE="HD2">I. Gas Well Completions and Workovers With Hydraulic Fracturing</HD>
                    <HD SOURCE="HD3">1. Summary of Final Amendments</HD>
                    <P>The EPA is finalizing certain revisions to calculation and reporting requirements in 40 CFR 98.233(g) and 98.236(g) for completions and workovers with hydraulic fracturing with several notable changes from the proposed requirements.</P>
                    <P>To calculate emissions from this source, reporters must use equation W-10A or W-10B. Both equations are designed to calculate the volumes of gas produced during the initial flowback, or pre-separation, stage and during the separation stage when sufficient quantities of gas are available to flow to a separator until the well moves to production. Flow rates in the separation stage are measured or calculated, but flow rates in the initial flowback period are currently based on a calculation assuming the gas flow rate in the initial stage is one half the gas flowrate at the beginning of the separation stage. Consistent with section II.B. of this preamble, the EPA is finalizing a change to equations W-10A and W-10B to allow use of multiphase flow meters to measure gas flow rates during the initial flowback stage as an alternative to assuming the flowrate is one half the flow rate at the beginning of separation. Reporters may choose either option to calculate the produced gas volume during the initial separation stage. To include measurement with multiphase flow meters as an option, the final rule includes minor changes from those proposed to equations W-10A and W-10B in 40 CFR 98.233(g) to allow reporters to choose either option, use of the original assumption of a flow rate that is half the flow rate at the beginning of separation or a measured flow rate using the multiphase meter. In addition, although we proposed removing the engineering equations to calculate flow rates for gas well completions, equations W-11A for sub-sonic flow and W-11B for sonic flow, following review and consideration of public comment, we are retaining these equations. The EPA is finalizing this change to the calculation methods in 40 CFR 98.233(g) from proposal to allow use of calculated flow rates for gas well completions using engineering equations only if it is not possible to measure the flow rate for use in equations W-10A and W-10B.</P>
                    <P>
                        The EPA is finalizing the rule to add reporting requirements in 40 CFR 98.236(g) to ensure consistency with requirements for the determination of gas flow volumes and gas composition in the flare stack emissions source. As discussed elsewhere in this preamble, the EPA is finalizing calculation and reporting requirements for natural gas emissions routed to the flare stacks from multiple sources. Reporters routing gas to a flare from hydraulically fractured completions and workovers must calculate CH
                        <E T="52">4</E>
                        , CO
                        <E T="52">2</E>
                         and N
                        <E T="52">2</E>
                        O emissions according to the calculation methods in 40 CFR 98.233(n), Flare stacks. Determination of gas flow volumes using continuous parameter monitoring systems is specified in 40 CFR 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and determination of gas composition use continuous gas composition analyzers or gas sampling is specified in 40 CFR 98.233(n)(4). If the reporter does not use continuous flow measurements, the reporter must calculate natural gas emissions routed to the flare using the calculation methods in 40 CFR 98.233(g) as specified in 40 CFR 98.233(n)(3)(ii)(B).
                    </P>
                    <P>In addition, the EPA is finalizing changes to reporting requirements in 40 CFR 98.236(g) from the proposal. In the final rule, reporters are required to indicate how the flow during the initial flowback period was determined. More specifically, reporters must indicate whether the flow rate during the initial flowback period was determined using a recording flow meter (digital or analog) at the beginning of the separation, using a multiphase flow meter or using one of the engineering equations, W11-A or W-11B. If a multiphase flowmeter was used to measure the flow rate during the initial flowback period, reporters are required to report the average flow rate measured by the multiphase flow meter from the initiation of flowback to the beginning of the period of time when sufficient quantities of gas present to enable separation in standard cubic feet per hour. We are also finalizing reporting requirements in 40 CFR 98.236(g) that require reporters to indicate whether the flow rate measured during the separation stage was measured using a using a recording flow meter (digital or analog) installed on the vent line or calculated through use of engineering equations W-11A or W-11B. In addition, we are finalizing proposals to add reporting of additional identifiers for completion and workover well type combinations, notably whether the well is flared or vented and whether or not it is a reduced emission completion or workover.</P>
                    <P>
                        As discussed above, the EPA is not finalizing the proposed removal of engineering equations W-11A and W-11B, the choke flow equations, which can be used with equation W-10A as an option to calculate back flow rates at gas well completions and workovers with hydraulic fracturing. The EPA had proposed removing this option, which allows reporters to use the engineering equation to calculate a flow rate for gas well completions and workovers rather than measuring the flow rate. Following receipt of comment and after further consideration, the EPA understands there may be situations in the field where measurement may not always be possible (for example, when a meter fails, if safety is at risk or for some other operational reason). In the 2023 Subpart W proposal, we explained that if we ultimately retained the choke flow 
                        <PRTPAGE P="42129"/>
                        equation, we planned to amend the reporting requirements in the final rulemaking to improve data quality and transparency. Therefore, we have added a new reporting requirement in 40 CFR 98.236(g) to require reporters that use equation W-10A to indicate whether the backflow rate for the representative well is measured using a flow meter or calculated using equations W-11A or W-11B. Under the existing regulations, reporters using equation W-10A to calculate emissions from gas well completions and workovers do not state in their annual GHGRP reports whether the emissions were calculated using a measured flow rate at the representative well or were calculated using the choke flow equations, equation W-11A or W-11B. Although this provides the EPA with an understanding of how many wells use a representative well as the basis to calculate emissions, we do not have any clarity on the number of wells that use the choke flow equations to calculate the gas flow rate for the representative wells versus those that use a measured flow rate at the representative wells. We believe reporting these data improves data quality by helping the EPA better understand how many reporters use the choke flow equations, the number of wells with completions and workovers with emission calculations based on choke flow equation measurements and the associated emissions. These additional data elements will provide the EPA with a better understanding of the bases for the reported emissions, which will improve the EPA's ability to verify the reported data and, ultimately, improve the accuracy of emissions.
                    </P>
                    <HD SOURCE="HD3">2. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to gas well completions and workovers with hydraulic fracturing.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Several commenters stated that existing methodologies for calculating emissions from oil and gas well completions and workovers with hydraulic fracturing are not based on empirical data, in particular when estimating emissions during the initial flowback period.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA disagrees with the commenters that proposed methodologies were not based on empirical data. The equations in 40 CFR 98.233(g) used to calculate emissions from these sources rely on empirical data measured for the well, including measured flowback flow rates at the start of separation and throughout the separation stage. The EPA acknowledges that equations W-10A and W-10B assume the average flow rate is one half of the flow rate at the beginning of separation, but we emphasize that the pre-separation flow rate is still calculated based on a measured separation flow rate. In addition, as described in the summary of final amendments for this source and later in this comment and response section, the EPA is finalizing revisions to the rule to allow use of multiphase flow meters during the initial pre-separation stage as an option to directly measure gas flow rates through the full initial flowback period. We intend to continue to assess alternatives for determining gas flow rates and flow volumes during the pre-separation stage.
                    </P>
                    <P>The current rule includes equations W-11A and W-11B, the choke flow equations, which are engineering equations that provide an option for calculating flow rates at gas wells when direct measurement is not possible. This final rule will continue to include these equations (as discussed later in this comment and response section) but we note that they also rely on well-specific and empirical data, such as the pressure upstream and downstream of the choke.</P>
                    <P>
                        <E T="03">Comment:</E>
                         The EPA received a comment with a suggestion to allow use of multiphase flow meters to measure backflow rates prior to the separation stage. The commenter stated that multiphase flow meters can measure oil, gas, and water without the need for separation and that, therefore, they are capable of measuring flowback from the beginning of flowback to the separation stage.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The commenter suggested use of a flowmeter upstream of the separator to measure flow rates during the initial flowback period to complement the existing use of flow meters downstream of the separator to measure flow rates once separation is possible, which is consistent with the purpose of the proposed amendments to add empirical methods to the provisions and a potential refinement of the existing calculation methodology to improve data quality. The EPA acknowledges that use of multiphase meters is growing in the oil and gas industry. In addition, given that current methodologies rely on gas flow rates metered during the separation stage to estimate the flow rate during the initial flowback period, the EPA agrees that using multiphase meters to directly measure the initial flowback period flow rates should improve the accuracy of emission estimates during the initial flowback period under the existing methodology. We are, therefore, amending 40 CFR 98.233(g) to include use of average flow rate measurements from multiphase flow meters as an option for calculating natural gas emissions during the initial flowback period. Correspondingly, in the final provisions the EPA is also finalizing changes to reporting requirements in 40 CFR 98.236(g) to require reporters to indicate whether they used a multiphase flow meter to calculate emissions from completions and workovers with hydraulic fracturing. Under the final provisions in 40 CFR 98.233(g), reporters may either use the assumption that the initial flowback rate is one half of the flowrate at the beginning of separation or use flow rates measured with a multiphase meter. While the EPA recognizes that multiphase metering upstream of a separator could potentially be used to extrapolate downstream flow rates, this would require complex modeling of the change in the thermodynamic state of the fluid between upstream and downstream conditions and an assumed separation efficiency to quantify the gas flow downstream of the separator. Therefore, after considering this and that use of a multiphase meter is a new approach to quantifying emissions from completions and workovers, when metering of the gas flow during the separation period is required under the final provisions, the EPA is continuing to require use of a flowmeter downstream of the separator even if a multiphase meter is placed upstream of the separator.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         The EPA received comments requesting to retain equations W-11A and W-11B, the choke flow equations, noting that these equations are used by reporters and further stating that the EPA provided no rationale as to why it proposed to remove this calculation option other than it is not used that often. In addition, several commenters also suggested that the EPA should consider allowing use of a Gilbert-type equation to be used to calculate gas flow rates. One commenter recommended that the EPA evaluate the use of a Gilbert-type equation while another commenter suggested replacing the existing choke flow equations with a Gilbert-type equation.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         In the 2023 Subpart W Proposal, we proposed removing equations W-11A and W-11B altogether, thus requiring use of measured flow rates at hydraulically fractured completions and workovers. Based on further consideration, including of the public comments we received, we recognize that field conditions, operating conditions, or health and safety considerations may preclude the use of flow meters to 
                        <PRTPAGE P="42130"/>
                        measure back flow rates in certain cases. Therefore, the EPA is retaining the existing choke flow equations, W-11A and W-11B, as an option in the final rule.
                    </P>
                    <P>The EPA is finalizing the rule without the addition of the Gilbert-type equation. We only proposed and sought comment on whether to remove the existing engineering equations; therefore, the suggestion to finalize the rule with a new engineering equation is outside the scope of this rulemaking. However, we thank the commenters for their suggestion and we may consider the equation in a future rulemaking.</P>
                    <P>We note that inputs to the equations are based on well-specific measurements for the orifice cross section, temperature, and pressure upstream and downstream of the choke. However, the EPA expects that flow rates determined based on direct measurements to be more accurate. Therefore, the rule is finalized to specify that the engineering equations can only be used when the reporter is unable to place a flow meter on the line to a vent or flare.</P>
                    <P>Finally, in the final rule, we have added a new reporting requirement in 40 CFR 98.236(g) to require reporters that use equation W-10A to indicate whether the backflow rate for the representative well is measured using a flow meter or calculated using equation W-11A or W-11B.</P>
                    <HD SOURCE="HD2">J. Blowdown Vent Stacks</HD>
                    <HD SOURCE="HD3">1. Summary of Final Amendments</HD>
                    <P>Subpart W currently requires reporting of blowdowns either using unique physical volume calculations by equipment or event types (40 CFR 98.233(i)(2)) or using flow meter measurements (40 CFR 98.233(i)(3)). The EPA is finalizing as proposed, consistent with section II.D. of this preamble, to move the listings of event types and the apportioning provisions to a new 40 CFR 98.233(i)(2)(iv) so that the introductory paragraph in 40 CFR 98.233(i)(2) would be more concise and provide clearer information regarding which requirements are applicable for each blowdown. Final 40 CFR 98.233(i)(2)(iv) includes separate paragraphs for each set of equipment and event type categories and provides clearer information regarding the applicable requirements for each industry segment.</P>
                    <P>
                        The EPA is finalizing as proposed revisions to the descriptions of the facility piping and pipeline venting categories, which were previously in 40 CFR 98.233(i)(2) and are now in the new 40 CFR 98.233(i)(2)(iv), to reflect the EPA's intent regarding which equipment or event type category is appropriate for each blowdown, consistent with section II.D. of this preamble. Our intent is that the “facility piping” equipment category is limited to unique physical volumes of piping (
                        <E T="03">i.e.,</E>
                         piping between isolation valves) that are located entirely within the facility boundary. In contrast, the intent for the “pipeline venting” equipment category is that a portion of the unique physical volume of pipeline is located outside the facility boundary and the remainder, including the blowdown vent stack, is located within the facility boundary. Additionally, we are finalizing as proposed the removal of the reference to “distribution” pipelines in the description of these two categories because we did not intend to limit the pipeline venting category to unique physical volumes that include such pipelines. Finally, we note that for the “facility piping” equipment category and the “pipeline venting” equipment category, the existing phrase “located within a facility boundary” in the descriptions of those categories generally refers to being part of the facility as defined by the existing provisions of subpart A or subpart W, as applicable, and we are not finalizing and did not propose to change that portion of those descriptions.
                    </P>
                    <P>We are finalizing as proposed the extension of the provisions in equation W-14A of 40 CFR 98.233(i)(2)(i) that allow use of engineering estimates based on best available information to determine the temperature and pressure of an emergency blowdown to the Onshore Natural Gas Transmission Pipeline segment, which aligns the requirements for the two geographically dispersed industry segments currently required to report blowdown vent stack emissions (Onshore Natural Gas Transmission Pipeline and Onshore Petroleum and Natural Gas Gathering and Boosting) and increases clarity of reporting requirements for Onshore Natural Gas Transmission Pipeline industry segment reporters, consistent with section II.D. of this preamble. As described in section III.C.1. of this preamble, we are also finalizing as proposed the use of engineering estimates to determine the temperature and pressure for emergency blowdowns in equation W-14A for the geographically dispersed industry segments that will begin reporting emissions from blowdown vent stacks (Onshore Petroleum and Natural Gas Production and Natural Gas Distribution).</P>
                    <P>As we explained at proposal, similar provisions to allow use of engineering estimates based on best available information to determine the temperature and pressure of an emergency blowdown were not added to equation W-14B of 40 CFR 98.233(i)(2)(i) in 2015 (80 FR 64262, October 22, 2015). We are finalizing as proposed to add provisions to equation W-14B of 40 CFR 98.233(i)(2)(i) to allow use of engineering estimates to determine the temperature and pressure of an emergency blowdown for both the geographically dispersed industry segments that currently report blowdown vent stack emissions (Onshore Natural Gas Transmission Pipeline and Onshore Petroleum and Natural Gas Gathering and Boosting) as well as the geographically dispersed industry segments that will be required to begin reporting blowdown vent stack emissions as described in section III.C.1. of this preamble (Onshore Petroleum and Natural Gas Production and Natural Gas Distribution), consistent with equation W-14A. Additional minor technical corrections for clarity associated with the blowdowns vent stack source are described in table 3 in section III.V. of this preamble.</P>
                    <P>After consideration of public comments, we are also finalizing additions to 40 CFR 98.236(i)(1) to specify how to assign blowdowns to a well-pad site or gathering and boosting site if a blowdown event is not directly associated with a specific well-pad or gathering and boosting site or could be associated with multiple well-pad or gathering and boosting sites. The final provisions direct reporters to associate the blowdown with either the nearest well-pad or gathering and boosting site upstream from the blowdown event or the well-pad or gathering and boosting site that represented the largest portion of the emissions for the blowdown event, as appropriate.</P>
                    <HD SOURCE="HD3">2. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to blowdown vent stacks.</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter stated that the EPA is proposing to require site-level details regarding blowdowns and recommended that the EPA instead allow reporters to aggregate events by type. The commenter stated that aggregating events by type would avoid line-by-line reporting per event and greatly reduce the complexity of reporting for the source category, without impacting data quality or transparency. The commenter also noted that some blowdowns such as mid-field pipeline blowdowns are not 
                        <PRTPAGE P="42131"/>
                        associated with a given well-pad or gathering station, so reporting those pipelines by site could be challenging. The commenter suggested allowing those types of blowdown events to be aggregated by county, which is consistent with other pipeline reporting under PHMSA.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA did not propose and is not taking final action in this rule to require individual blowdown reporting. The EPA did propose, and is finalizing, reporting of certain emission source types by well-pad site or gathering and boosting site, as described further in section III.D. of this preamble. To implement those provisions, the EPA is finalizing as proposed the additional requirement to report a well-pad ID or gathering and boosting site ID for blowdowns at facilities in the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments, respectively, so that blowdown event reporting in these industry segments is aggregated by equipment or event type at each well-pad site or gathering and boosting site for facilities, as appropriate. To further clarify this in the final provision, the EPA is moving the requirement to report the equipment or event type from the introductory text of 40 CFR 98.236(i)(1) to a separate reporting element in 40 CFR 98.236(i)(1)(ii).
                    </P>
                    <P>Regarding the concern with reporting a site for mid-field pipeline blowdowns or other similar circumstances, in the final provisions, the EPA has provided guidance in 40 CFR 98.236(i)(1) and (2) to assist with these kinds of determinations. The final provisions direct reporters to associate the blowdown with either the nearest well-pad or gathering and boosting site upstream from the blowdown event or the well-pad or gathering and boosting site that represented the largest portion of the emissions for the blowdown event, as appropriate. This approach for reporting is more appropriate for the final rule than a county-based approach because very little data will be reported on a county (or sub-basin) basis with the changes in reporting levels described in section III.D. of this preamble. Further, it is similar to the established approach for assigning blowdowns and emissions to an equipment or event type when a blowdown event results in emissions from multiple equipment or event types.</P>
                    <HD SOURCE="HD2">K. Atmospheric Storage Tanks</HD>
                    <HD SOURCE="HD3">1. Open Thief Hatches</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>The EPA is finalizing several amendments regarding thief hatch monitoring on atmospheric storage tanks. These revisions to the atmospheric tank calculation methodologies and reporting requirements will help quantify the impact of open thief hatches on atmospheric storage tank emissions and enhance the overall quality of the data collected under the GHGRP, consistent with section II.B. of this preamble.</P>
                    <P>The EPA is finalizing as proposed revisions to 40 CFR 98.233(j)(4) that specifically state that emissions vented directly to the atmosphere during times of reduced control system capture efficiency are required to be calculated. Reduced capture efficiency may occur during periods when the control device is not operating or is not effectively capturing emissions, such as when thief hatches are open or due to other causes such as open pressure relief devices.</P>
                    <P>We are also finalizing as proposed the calculation methodology in 40 CFR 98.233(j)(4) for determining reduced capture efficiencies when a control device is in use but a thief hatch is open. We are finalizing revisions to 40 CFR 98.233(j)(4)(i)(C) to require facilities to assume that no emissions are captured by the control device (0 percent capture efficiency) when the thief hatch on a tank is open, with one revision. After consideration of comments received, we are clarifying in 40 CFR 98.233(j)(4)(i)(C) that a thief hatch is open if it is fully or partially open such that there is a visible gap between the hatch cover and the hatch portal, as the EPA did not intend for leaks from an open thief hatch that are only identifiable using OGI technologies to be required to assume a capture efficiency of zero.</P>
                    <P>The EPA is finalizing the requirements of 40 CFR 98.233(j)(7) to require monitoring of the thief hatch with revisions from proposal. We are finalizing as proposed that if a thief hatch sensor is present and operating on the tank, sensor data must be used to inform the periods of time that a thief hatch is open. Regarding the proposed revision that the thief hatch sensor must be capable of transmitting and logging data whenever a thief hatch is open and when the thief hatch is subsequently closed, in the final provision we removed the requirement that the sensor be capable of transmitting data, in order to include use of sensor data in situations where the sensor has local logging capabilities but is not able to remotely transmit the data. Additionally, after consideration of comments, we are adding in the final provisions a requirement that if a thief hatch sensor is not operating but a tank pressure sensor is operating on a controlled atmospheric pressure storage tank, reporters must use data obtained from the pressure sensor to determine periods when the thief hatch is open. Similar to an applicable thief hatch sensor, an applicable operating tank pressure sensor must be capable of logging tank pressure data. It is expected that operators would assume that a pressure indication outside of normal operating range would indicate an issue with the thief hatch. Pressure indication is similar in accuracy as a visual inspection in the case of open thief hatches.</P>
                    <P>
                        The EPA is finalizing the requirements in 40 CFR 98.233(j)(7) as proposed with revisions to clarify that if neither an applicable thief hatch sensor nor an applicable tank pressure sensor is operating on the controlled atmospheric storage tank, reporters must perform a visual inspection of each thief hatch on a controlled atmospheric storage tank. We are further clarifying in the final rule that visual inspections in accordance with 40 CFR 98.233(j)(7)(i) through (iii) must be performed for tanks equipped with thief hatch or pressure sensors during periods of time when the thief hatch or pressure sensor is not operating or malfunctioning for longer than 30 days. We feel that 30 days is a reasonable amount of time during which the facility can return the sensor back into service before triggering a visual inspection requirement to assure proper operation of the equipment. This is similar to the requirements for continuous flare pilot flame monitoring that requires a monthly visual inspection (which is the requirement in absence of continuous monitoring) if the continuous monitoring device is out of service for more than 4 weeks. We are finalizing 40 CFR 98.233(j)(7)(i) with a correction to an inadvertent error from proposal, requiring that if the thief hatch is required to be monitored as part of a cover or closed vent system, rather than to comply with requirements of 40 CFR 60.5397b, to comply with 40 CFR 60.5395b or the applicable EPA-approved state plan or the applicable Federal plan in 40 CFR part 62 on a controlled atmospheric storage tank, visual inspections must be conducted at least as frequent as the required AVO inspection described in 40 CFR 60.5416b or the applicable EPA-approved state plan or the applicable Federal plan in 40 CFR part 62, or annually (whichever is more frequent). A similar correction is also being made to 40 CFR 98.233(j)(7)(ii). Additionally, we are removing the phrase “fugitive emissions” from 40 CFR 98.233(j)(7)(i) 
                        <PRTPAGE P="42132"/>
                        and (ii) as tank covers are not considered fugitive emission components under the updated cross-referenced provisions. We are finalizing the requirements in 40 CFR 98.233(j)(7)(ii) and (iii) as proposed, which require visual inspections once per calendar year, at a minimum, for tanks not equipped with thief hatch or pressure sensors and for tanks with malfunctioning thief hatch or pressure sensors. We are finalizing as proposed that if one visual inspection is conducted in the calendar year and an open thief hatch is identified, the reporter is required to assume that the thief hatch had been open for the entire calendar year or the entire period that the sensor(s) was not operating or malfunctioning if the visual inspection occurred during the period in which it was malfunctioning or not operating. If multiple visual inspections are conducted in the calendar year and an open thief hatch is identified, the reporter is required to assume that the thief hatch had been open since the preceding visual inspection (or the beginning of the year if the inspection was the first performed in a calendar year) through the date of the visual inspection (or the end of the year if the inspection was the last performed in a calendar year).
                    </P>
                    <P>We are finalizing the reporting requirements for open thief hatches in 40 CFR 98.236(j) as proposed. We are finalizing the addition of 40 CFR 98.236(j)(1)(x)(F) to require reporting of the number of controlled atmospheric storage tanks with open thief hatches within the reporting year, as well as the addition of 40 CFR 98.236(j)(1)(xv) to require reporting of the total volume of gas vented through the open thief hatches, for Calculation Methods 1 and 2. We are finalizing similar requirements for atmospheric storage tanks with emissions calculated using Calculation Method 3 in 40 CFR 98.236(j)(2)(ii)(D) and (H) for hydrocarbon liquids tanks and 40 CFR 98.236(j)(2)(iii)(D) and (F) for produced water tanks.</P>
                    <P>We are finalizing the revisions in 40 CFR 98.233(j)(4)(i)(D) as proposed to require facilities to account for time periods of reduced capture efficiency from causes other than open thief hatches when determining total emissions vented directly to atmosphere based on best available data, with one clarification. As described for open thief hatches, the EPA understands that pressure monitoring data may be used to determine when a pressure relief device is open and venting to the atmosphere on a controlled atmospheric storage tank. Thus, the EPA is clarifying in 40 CFR 98.233(j)(4)(i)(D) that best available data may include, but is not limited to, data from operating pressure sensors on atmospheric pressure storage tanks. In cases where a pressure relief device is open, reporters must use pressure sensor data (if available) to assist in the determination of the duration of the release and use best available data to determine the reduction in capture efficiency.</P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to open thief hatches on atmospheric storage tanks.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Several commenters requested that the EPA provide a definition of an open or not properly seated thief hatch and clarify whether leaks that can only be identified through use of an OGI camera or similar detection technology do not meet the definition of an open or not properly seated thief hatch. Many commenters noted that it is inaccurate to assume a small, wisping leak only seen through an OGI camera would require an operator to assume 0 percent capture efficiency when most of the storage tank vapors remain in the tank, are captured, or are routed to a control device. Additionally, commenters noted that small leaks would not be identified with the proposed technology suggested by the EPA: thief hatch sensor or visual inspection monitoring methods.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         In the final rule, the EPA is removing from the proposed provisions the phrase “not properly seated” in 40 CFR 98.233(j)(4)(i)(C) through (D) and 40 CFR 98.233(j)(4)(ii) and instead specifying that a thief hatch is open if it is fully or partially open such there is a visible gap between the hatch cover and the hatch portal. The requirements to perform a visual inspection to identify a gap on applicable atmospheric storage tank thief hatches would not necessitate the use of OGI technologies to identify emissions. Thus, in this final rule, emissions from an open thief hatch that are only identifiable using OGI technologies would not be required to assume a capture efficiency of 0 percent but these emissions would still have to be quantified under 40 CFR 98.233(j)(4)(i)(D) based on best available data, including any data from operating pressure sensors on atmospheric pressure storage tanks. A visible gap creates a larger more direct path of emissions to the atmosphere, so we are maintaining the assumed a 0 percent capture efficiency for this case. While we are not requiring emissions that are only identifiable using OGI technologies to assume a capture efficiency of 0 percent, such emissions identified through OGI may still constitute a violation of emission standards under NSPS OOOOb or a state or federal plan implementing EG OOOOc.
                    </P>
                    <P>We note that we may consider the option of incorporating thief hatches into the leak requirements in 40 CFR 98.233(q) and (r) in future rulemakings.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Many commenters requested that tank pressure sensors be acceptable to determine if tank thief hatches are open or not properly seated. One commenter stated that on controlled tanks, these sensors will register (for example) between 0.8 and 8 pounds of pressure. The commenter notes that a pressure indication outside of this range would indicate an issue with the thief hatch. Pressure indication could in fact be more accurate than a visual inspection in the case of a not properly seated thief hatch.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA agrees with the commenters that the use of pressure monitors on atmospheric storage tanks are appropriate for determining the duration of time a thief hatch is open. The EPA concurs with commenters that, on controlled tanks, pressure sensors will typically register within a normal operating range (
                        <E T="03">e.g.,</E>
                         between 0.8 and 8 pounds of pressure). If a thief hatch is open, the tanks will not build up pressure. A pressure indication outside of the normal operating range would indicate an issue with the thief hatch and could be used to determine duration of a thief hatch opening. Thus, in the final rule, we are adding language to 40 CFR 98.233(j)(7) to include requirements for the use of pressure sensors on applicable atmospheric storage tanks with thief hatches. Specifically, we are adding language to specify that if a thief hatch sensor is not operating but a pressure sensor is present and operating on the tank, pressure sensor data must be used to inform the periods of time that a thief hatch is open. The thief hatch sensor must be capable of logging data whenever a thief hatch is open and when the thief hatch is subsequently closed. We agree that including requirements for the use of pressure sensor data for open thief hatch determinations as specified in the final provisions will improve the accuracy of reported emissions and incorporate empirical data.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter noted that thief hatch sensors do periodically malfunction and may falsely indicate an open thief hatch. The commenter requested that the EPA allow reporters to exclude thief hatch sensor 
                        <PRTPAGE P="42133"/>
                        malfunction periods and instead use best available monitoring data (
                        <E T="03">e.g.,</E>
                         TEMS, other parametric monitoring, last inspection) when determining the time that the thief hatch was open in calculating and reporting storage tank emissions.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         In the final rule, the EPA is finalizing that operators are required to use thief hatch sensors or pressure monitors where they are already installed and operating, which implies properly functioning equipment. As proposed, the EPA states in 40 CFR 98.233(j)(7) that thief hatch sensors (and in the final rule, pressure monitors) must be capable of logging data whenever the thief hatch is open. Thus, malfunctioning equipment would not meet these requirements and should not be used to determine periods of time when thief hatches are open. In the final rule, the EPA is further clarifying that during periods of time when the sensor is malfunctioning for periods greater than 30 days, facilities must perform visual inspections and determine thief hatch opening durations according to the methodologies in 40 CFR 98.233(j)(7)(i) through (iii).
                    </P>
                    <HD SOURCE="HD3">2. Malfunctioning Dump Valves</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        The EPA is finalizing as proposed revisions to the equation variables (particularly the subscripts) in equation W-16 to clarify the intent of this equation. Specifically, we are finalizing the change of the variable “E
                        <E T="52">n</E>
                        ” to “E
                        <E T="52">s,i</E>
                        ” to further clarify that these are the volumetric atmospheric storage tank emissions determined using the procedures in 40 CFR 98.233(j)(1), (2), and, if applicable, (j)(4). We are also finalizing the replacements of the “n” and “o” subscripts in the other variables with a “dv” subscript to indicate that these are the emissions from periods when the gas-liquid separator dump valves were not closed properly and that the emissions from these periods should be added to the emissions determined using the procedures in 40 CFR 98.233(j)(1), (2), and, if applicable, (j)(4).
                    </P>
                    <P>
                        The EPA is finalizing the requirements of 40 CFR 98.233(j)(5)(i) to require monitoring of the gas-liquid separator liquid dump valve with revisions from proposal, consistent with section II.B. of this preamble. In the final rule, we are adding after consideration of comment that if a parametric monitor is present and operating on the tank or gas-liquid separator, then the parametric monitor data must be used to inform the periods of time that a dump valve is stuck in an open or partially open position as well as when the dump valve is subsequently closed. Similar to pressure sensors on thief hatches, it is expected that operators would assume that a parameter (
                        <E T="03">e.g.,</E>
                         pressure, temperature, flow) indication outside of normal operating range would indicate an issue with the dump valve. Parameter indication is similar in accuracy as a visual inspection in the case of malfunctioning dump valves. We are also finalizing that the parametric monitor must be capable of logging data whenever a gas-liquid separator liquid dump valve is stuck in an open or partially open position and when the gas-liquid separator liquid dump valve is subsequently closed, which will allow reporters to accurately determine the time input for equation W-16 (T
                        <E T="52">dv</E>
                        ).
                    </P>
                    <P>The EPA is finalizing the requirement to perform routine visual inspections of separator dump valves to determine if the valve is stuck in an open or partially open position when an applicable parametric monitor is not present or is not operating, with a revisions from proposal that expands the inspections to also include audio and olfactory inspections. Audio, visual, and olfactory (AVO) inspections would be required once per calendar year, at a minimum. Similar to the provisions of 40 CFR 98.233(q) and 40 CFR 98.233(j)(7), if one AVO inspection is conducted in the calendar year and a stuck dump valve is identified, the reporter is required to assume that the dump valve had been stuck open for the entire calendar year. If multiple AVO inspections are conducted in the calendar year and a stuck dump valve is identified, the reporter is required to assume that the dump valve had been stuck open since the preceding AVO inspection (or the beginning of the year if the inspection was the first performed in a calendar year) through the date of the AVO inspection (or the end of the year if the inspection was the last performed in a calendar year). The EPA determined that this is an appropriate methodology as it is consistent with the inspection requirements for dump valves under 40 CFR 98.233(k).</P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to malfunctioning dump valves on separators feeding on atmospheric storage tanks.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Many commenters requested that parametric monitoring be acceptable to determine if a gas-liquid separator liquid dump valve is stuck in an open or partially open position. Additionally, commenters noted that an effective approach to identify stuck dump valves involves auditory inspections of the tank, particularly in cases where tanks are designed with submerged fill—a stuck dump valve allowing gas flow into the tank produces noticeable “bubbling” sounds.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA agrees with the commenters that the use of parametric monitors on atmospheric storage tanks and gas-liquid separators are appropriate for determining the duration of time a gas-liquid separator liquid dump valve is stuck in an open or partially open position. The EPA concurs that, for operators of high-pressure gas-liquid separators, wells will be shut-in or there will be alarms requiring immediate response due to the separator reaching low liquid level, which will happen if a gas-liquid separator liquid dump valve is stuck in an open position. In other cases, operators will also monitor the density of the fluid going to the tank and alarms on low density will trigger follow up to inspect for a malfunctioning gas-liquid separator liquid dump valve. Thus, in the final rule, we are adding appropriate language to 40 CFR 98.233(j)(5)(i) to include the use of parametric monitors on applicable atmospheric storage tanks and gas-liquid separators. We agree that including use of parametric monitoring data to determine whether or not a dump valve is stuck open as specified in the final provisions will improve the accuracy of reported emissions and incorporate empirical data.
                    </P>
                    <P>The EPA also agrees that, for those tanks and separators without a parametric monitor, auditory inspections should be used in conjunction with visual inspections to determine if a gas-liquid separator liquid dump valve is stuck in an open or partially open position. We agree that an effective approach to identify stuck gas-liquid separator liquid dump valves involves auditory inspections of the tank, particularly in cases where tanks are designed with submerged fill—a stuck dump valve allowing gas flow into the tank produces noticeable “bubbling” sounds. In the final rule, we are clarifying in 40 CFR 98.233(j)(5) that AVO inspections must be performed to determine if a gas-liquid separator liquid dump valve is stuck in an open or partially open position.</P>
                    <HD SOURCE="HD3">3. Applicability and Selection of Appropriate Calculation Methodologies for Atmospheric Storage Tanks</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        The EPA is finalizing several revisions with regard to the 
                        <PRTPAGE P="42134"/>
                        applicability and selection of an appropriate calculation methodology for atmospheric storage tanks, consistent with sections II.B. and II.C. of this preamble. The EPA is finalizing revisions to the introductory text of 40 CFR 98.233(j) as proposed to add language that clearly states that the annual average daily throughput of hydrocarbon liquids should be based on flow out of the separator, well, or non-separator equipment determined over the actual days of operation. We are also finalizing certain changes to the introductory text in 40 CFR 98.233(j) as proposed, which amends the requirements in 40 CFR 98.233(j) to specify that reporters may use Calculation Method 1, Calculation Method 2, or Calculation Method 3 when determining emissions from atmospheric storage tanks receiving hydrocarbon liquids flowing out of wells, gas-liquid separators, or non-separator equipment with throughput greater than 0 barrels per day and less than 10 barrels per day. After consideration of comments, we are finalizing the conditions under which a facility is required to use 40 CFR 98.233(j)(1) with a modification. The proposed requirement stated that if reporters conduct modeling for environmental compliance or reporting purposes, including but not limited to compliance with Federal or state regulations, air permit requirements, or annual inventory reporting, or internal review, they would use those results for reporting under subpart W. Based on consideration of public comment concerning the nature of modeling for internal review purposes by facilities, and differences in program requirements, we are not finalizing the proposed requirement to use the results from such modeling for reporting under subpart W. We are instead requiring in the final provisions that if a facility is required to use a software program for compliance with federal or state regulations, air permit requirements or annual emissions inventory reporting that meets the requirements of in 40 CFR 98.233(j)(1), they must use 40 CFR 98.233(j)(1) for reporting under subpart W. We anticipate that modeling consistent with the methodology outlined in 40 CFR 98.233(j)(1) could be conducted by reporters for environmental compliance or reporting purposes or reporters may run a simulation solely for the purpose of reporting under subpart W. This will ensure that the facility is able to use modeling results that are representative of actual operating conditions and meet the requirements of 40 CFR 98.233(j)(1) without requiring that models completed for other purposes meet the requirements under this subpart.
                    </P>
                    <P>
                        We are finalizing the removal of the “fixed roof” language when referring to atmospheric pressure storage tanks subject to 40 CFR 98.233(j) as proposed. We are also finalizing revisions to 40 CFR 98.236(j)(1)(x) and 40 CFR 98.236(j)(2)(i) to require separate reporting of the total count of fixed roof and floating roof tanks at the facility. We are finalizing revisions of all instances of “storage tanks,” “atmospheric tanks,” and “tanks” in 40 CFR 98.233(j) and 40 CFR 98.236(j) to instead use the term “atmospheric pressure storage tanks” as proposed. We are finalizing the addition of a definition for an atmospheric pressure storage tank as proposed, which is defined as “a vessel (excluding sumps) operating at atmospheric pressure that is designed to contain an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water and that is constructed entirely of non-earthen materials (
                        <E T="03">e.g.,</E>
                         wood, concrete, steel, plastic) that provide structural support. Atmospheric pressure storage tanks include both fixed roof tanks and floating roof tanks. Floating roof tanks include tanks with either an internal floating roof or an external floating roof.”
                    </P>
                    <P>We are moving the last sentence of 40 CFR 98.233(j), which contains reference to “paragraph (j)(4) of this section” to be located prior to discussion of “paragraph (j)(5) of this section” so that paragraph references appear in the order in which they are contained in the regulatory text. Relatedly, we are also deleting the sentence immediately following discussion of “paragraph (j)(5) of this section” because it is largely duplicative of the moved last sentence of 40 CFR 98.233(j), as proposed.</P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to the application and selection of appropriate calculation methodologies for atmospheric storage tanks.</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter reported that simulations run for “internal review” for a variety of purposes, including “what-if” scenarios (
                        <E T="03">i.e.,</E>
                         exploring possible engineering adjustments) may not meet the EPA's goal of estimating emissions based on operating conditions. The commenter recommended that only simulations run for compliance purposes should be used.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We agree with the commenter that simulations run for other purposes may not result in emissions estimations based on representative operating conditions, as facilities may complete models for a variety of purposes, including models to consider future adjustments to the operation of the unit that are based on possible future, not actual, operating conditions. We are not finalizing the proposed requirement that all results from simulations run for the purposes of “internal review” or modeling completed for environmental compliance or reporting purposes are required to be used for reporting. We are instead requiring in the final provisions that if a facility performs emissions modeling for compliance with federal or state regulations, air permit requirements or annual emissions inventory reporting using a software program that meets the requirements of 40 CFR 98.233(j)(1), they must also use 40 CFR 98.233(j)(1) for reporting under subpart W. We expect that these amendments as finalized will increase the quality of data collected without requiring the inclusion of results from inappropriate modeling runs. We have revised the language in 40 CFR 98.233(j) introductory text to clarify these requirements.
                    </P>
                    <HD SOURCE="HD3">4. Controlled Atmospheric Storage Tanks</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        The EPA is finalizing the revisions to the methodologies for calculating controlled atmospheric storage tanks emissions vented directly to the atmosphere in 40 CFR 98.233(j)(4), consistent with section II.D. of this preamble. We are finalizing 40 CFR 98.233(j)(4)(i) with modifications from proposal. As proposed, the methodology under 40 CFR 98.233(j)(4)(i) for calculating emissions vented to the atmosphere during periods of reduced capture efficiency of the vapor recovery system or flare (
                        <E T="03">e.g.,</E>
                         when a thief hatch is open or not properly seated or when a pressure relief valve is open) first required reporters to determine the maximum potential vented emissions as specified under 40 CFR 98.233(j)(1), (2), or (3) per 40 CFR 98.233(j)(4)(i)(A). In the final rule, the EPA is removing the term “maximum potential” from 40 CFR 98.233(j)(4)(i)(A); while this term was meant to signify that reporters should not reduce for controls at this step of the calculation, we understand that the terminology may have been confused for worst-case condition potential-to-emit (PTE) emissions. Thus, in the final rule, the EPA is adding language to 40 CFR 
                        <PRTPAGE P="42135"/>
                        98.233(j)(4)(i)(A) to clarify consistent with our original intent.
                    </P>
                    <P>The provisions for calculating recovered mass in 40 CFR 98.233(j)(4)(ii) are being finalized as proposed. For flared atmospheric storage tank emissions, the revisions to 40 CFR 98.233(j), which direct reporters to the methodologies in 40 CFR 98.233(n), are being finalized as proposed. While the final flaring provisions differ somewhat from the proposed provisions, as explained in more detail in section III.N. of this preamble, the final amendments generally specify as proposed that vented atmospheric storage tank emissions include only those emissions vented directly to the atmosphere and emissions routed to a flare are considered flare stack emissions.</P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to the calculation and reporting of emissions from controlled atmospheric storage tanks.</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter requested that the EPA remove the term “maximum potential” from 40 CFR 98.233(j)(4)(i)(A), as assuming worst-case conditions would be required to determine a maximum potential case, which does not reflect actual operations. The commenter states that this does not further the EPA's goal of accurately determining emissions.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA did not intend for reporters to calculate emissions using worst-case conditions for this step of the calculation methodology for controlled atmospheric storage tank emissions. Rather, the EPA had intended the language to signify that reporters should calculate their vented emissions from the atmospheric storage tank without reducing emissions for controls. However, we agree with the commenter that this language could be misunderstood. In the final rule, the EPA is revising 40 CFR 98.233(j)(4)(i)(A) from proposal by removing the proposal term “maximum potential” and adding language to clarify that emissions in this step of the methodology should represent the emissions from the atmospheric storage tank prior to the vapor recovery system or flare, consistent with the original intent of the provision.
                    </P>
                    <HD SOURCE="HD3">5. Calculation Methods 1 and 2 for Atmospheric Storage Tanks</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        The EPA is finalizing that reporters would collect measurements of the simulation input parameters listed under 40 CFR 98.233(j)(1)(i) through (vii), consistent with section II.B. of this preamble, with the following changes from proposal. After consideration of comments received, in an effort to reduce burden on reporters, we are specifying that, with the exception of the API gravity, composition and Reid vapor pressure required by 40 CFR 98.233(j)(1)(iii) and (vii), the measurements must be taken at least annually since the maximum time period covered by a simulation would be the reporting year, as we expect these measurements to be more easily attainable or significantly variable between reporting years. For API gravity, composition, and Reid vapor pressure, and per 40 CFR 98.233(j)(1)(iii) and (vii), measurements would be required to be conducted within six months of start-up or by January 1, 2030 (
                        <E T="03">i.e.,</E>
                         within five years of the effective date of the rule), whichever is later, and at least once every five years thereafter. Relatedly, we are combining the API gravity model input at 40 CFR 98.233(j)(1)(iii) with the composition and Reid vapor pressure model inputs at 40 CFR 98.233(j)(1)(vii) so that all model input parameters with the sampling frequency different from annual are contained in the same subparagraph. Until such time that a sample can be collected, reporters may continue to determine API gravity by engineering estimate and process knowledge based on best available data and composition and Reid vapor pressure by using one of the existing methods described in 40 CFR 98.233(j)(1)(vii)(A) through (C). We are finalizing similar edits in 40 CFR 98.233(j)(2)(i). We are also finalizing the removal of the provisions of 40 CFR 98.233(j)(2)(ii) and (iii) as proposed, which allowed for representative compositions to be used for tanks receiving liquids directly from wells or non-separator equipment. For the measured parameters in 40 CFR 98.233(j)(1)(i) through (vii), we are clarifying in the final rule that measurements must only be taken if the parameter is an input to the modeling software selected by the reporter.
                    </P>
                    <P>We are finalizing the addition of ProMax as an example software program for calculating atmospheric tank emissions per 40 CFR 98.233(j)(1) as proposed, consistent with section II.B. of this preamble. Consistent with the EPA's revisions to 40 CFR 98.233(e)(1) for dehydrators, the EPA is requiring the use of ProMax version 5.0 or above.</P>
                    <P>The EPA is finalizing the amendments to 40 CFR 98.233(j) as proposed such that facilities with wells flowing directly to atmospheric storage tanks without passing through a separator may use either Calculation Method 1, Calculation Method 2, or, for wells, gas-liquid separators, or non-separator equipment with annual average daily throughput greater than 0 barrels per day and less than 10 barrels per day, Calculation Method 3, consistent with section II.B. of this preamble. We are also finalizing the conforming edits within 40 CFR 98.233(j)(1) and (2) and 40 CFR 98.236(j)(1) to refer to parameters and requirements for wells flowing directly to atmospheric storage tanks.</P>
                    <P>
                        We are finalizing the reorganization of the reporting requirements in 40 CFR 98.236(j)(1) as proposed, consistent with section II.C. of this preamble. In the final rule, tank counts are collected under 40 CFR 98.236(j)(1)(x)(A) through (F), and the reporting of CO
                        <E T="52">2</E>
                         and CH
                        <E T="52">4</E>
                         vented emissions and recovered mass is reported under 40 CFR 98.236(j)(1)(xi) through (xiv). The EPA is also finalizing the removal of 40 CFR 98.236(j)(1)(xi) as proposed. The EPA is finalizing 40 CFR 98.236(j)(1)(vii) and (viii) with revisions from proposal to require the flow-weighted average concentration (mole fraction) of CO
                        <E T="52">2</E>
                         and CH
                        <E T="52">4</E>
                         in the flash gas, rather than the minimum and maximum values, for only those reporters that used Calculation Method 1 to determine emissions from atmospheric storage tanks.
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to calculation methodologies 1 and 2 for atmospheric storage tanks.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Several commenters requested clarification on whether the EPA intends for input parameters to model tank emissions calculated using Calculation Method 1 to be measured annually. Commenters requested a five-year measurement time frame in which measurements are gathered every five years due to the high level of burden that the measurement and sampling requirements impose.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The proposed requirements to measure certain inputs for Calculation Methods 1 and 2 were not prescriptive with regard to a time frame to obtain measurements. The EPA only specified in 40 CFR 98.233(j) that if an applicable parameter must be measured, the reporter must “collect measurements reflective of representative operating conditions over the time period covered by the simulation.”
                        <PRTPAGE P="42136"/>
                    </P>
                    <P>Regarding the frequency of measurement, as explained in the preamble to the 2023 Subpart W Proposal, we proposed that reporters would collect measurements reflective of representative operating conditions over the time period covered by the simulation. In addition, we proposed that the parameters that must be used to characterize emissions should reflect operating conditions over the time period covered by the simulation rather than just over the calendar year. Under this proposed change, reporters could continue to run the simulation once per year with parameters that are determined to be representative of operating conditions over the entire year. Alternatively, reporters would be allowed to conduct periodic simulation runs to cover portions of the calendar year, as long as the entire calendar year is covered. The reporter would then sum the results at the end of the year to determine annual emissions. In that case, the parameters for each simulation run would be determined for the operating conditions over each corresponding portion of the calendar year.</P>
                    <P>Requirements for measurement frequency for 40 CFR 98.233(j)(1)(i) through (vi) are being clarified in the final provisions to specify that for these input parameters, the measurements must be taken at least once per year where parameters are determined to be representative of operating conditions over the entire year, or the measurements must be taken multiple times per year, where the measurements are reflective of representative operating conditions over shorter time periods. However, after consideration of the significant burden noted by commenters to sample all hydrocarbon liquid and produced water storage tanks within their facility each reporting year, the EPA is finalizing a reduced frequency schedule in 40 CFR 98.233(j)(1)(vii) for API gravity, composition and Reid vapor pressure sampling and analysis from each well, separator, or non-separator equipment. Reporters must sample and analyze sales oil or stabilized hydrocarbon liquids for API gravity, hydrocarbon liquids or produced water composition, and hydrocarbon liquids Reid vapor pressure within six months of equipment star-up, or by January 1, 2030, whichever is later, and at least once every five years thereafter. Until such time that a sample can be collected from the well, separator, or non-separator equipment, reporters may determine API gravity by engineering estimate and process knowledge based on best available data, and composition and Reid vapor pressure using one of the representative methods in 40 CFR 98.233(j)(1)(vii)(A) through (C). We believe that measurements taken at this frequency will be sufficiently representative of the API gravity, composition and Reid vapor pressure as we do not expect significant changes in comparison to cases where physical or operational changes, such as when a well feeding the atmospheric pressure storage tank undergoes fracturing or refracturing, are made.</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter stated that not all process simulation software requires all of the input parameters listed in 40 CFR 98.233(j)(1) to run the model. The commenter noted that in some process simulators (
                        <E T="03">e.g.,</E>
                         BR&amp;E ProMax, AspenTech HYSYS), if a hydrocarbon liquids composition is provided for the tank feed, API gravity and Reid Vapor Pressure are not needed as inputs to the simulation as these can be calculated from the other input parameters.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA understands that the different modeling software options available to reporters may require different input parameters in order to produce an accurate emissions estimate for atmospheric tanks. We agree with the commenter that only the input parameters that are required to run the model need to be measured. Therefore, in the final rule, the EPA is clarifying the language in 40 CFR 98.233(j)(1)(i) through (vii) to reflect this.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter noted that additional edits are required to 40 CFR 98.236(j)(1)(vii) and (viii), as these requirements to report flash gas CO
                        <E T="52">2</E>
                         and CH
                        <E T="52">4</E>
                         concentrations seem to be specific to Calculation Method 1. The commenter stated that for Calculation Method 2, reporters must assume the CO
                        <E T="52">2</E>
                         and CH
                        <E T="52">4</E>
                         in solution from the oil sent to tanks is emitted to atmosphere, so the concentrations of CO
                        <E T="52">2</E>
                         and CH
                        <E T="52">4</E>
                         in the flash gas are not known.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA agrees with the commenter that, for reporters using the emissions calculation methodology described in 40 CFR 98.233(j)(2), facilities must assume all CO
                        <E T="52">2</E>
                         and CH
                        <E T="52">4</E>
                         in solution from hydrocarbon liquids sent to tanks would be emitted to atmosphere. Therefore, the EPA agrees that these flash gas concentrations for these GHGs are not known when using Calculation Method 2 and so has revised 40 CFR 98.236(j)(1)(vii) and (viii) to be only applicable when Calculation Method 1 is used.
                    </P>
                    <HD SOURCE="HD3">6. Calculation Method 3 for Atmospheric Storage Tanks</HD>
                    <P>
                        The EPA is finalizing amendments for Calculation Method 3 atmospheric storage tanks as proposed, consistent with section II.C. of this preamble. The EPA received only minor comments regarding the revisions to Calculation Method 3 for atmospheric storage tanks. See the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
                    </P>
                    <P>
                        The EPA is finalizing amendments to 40 CFR 98.233(j)(3) as proposed to clarify that the separators, wells, or non-separator equipment for which emissions are calculated should be those with annual average daily hydrocarbon liquids throughput greater than 0 barrels per day and less than 10 barrels per day (
                        <E T="03">i.e.,</E>
                         the count variable in equation W-15A should not include separators, wells, or non-separator equipment that had no throughput during the year). Similarly, we are also finalizing amendments as proposed to clarify that the count of separators, wells, or non-separator equipment to report under 40 CFR 98.236(j)(2)(ii)(E) should also be those with annual average daily hydrocarbon liquids throughput greater than 0 barrels per day and less than 10 barrels per day.
                    </P>
                    <P>The EPA is also finalizing as proposed amendments to require reporting of all Calculation Method 3 emissions that are vented directly to atmosphere under 40 CFR 98.236(j)(2)(ii). These revisions amend subpart W to no longer require separate reporting of Calculation Method 3 emissions from atmospheric storage tanks that did not control emissions with flares and those that controlled emissions with flares.</P>
                    <P>
                        The EPA is finalizing as proposed amendments to 40 CFR 98.236(j)(2)(ii)(E) to request the total number of separators, wells, or non-separator equipment used to calculate Calculation Method 3 storage tank emissions. This revision will completely align the reporting requirement with the total “Count” input variable in equation W-15A. We are also finalizing requirements to collect this information at the well-pad site, gathering and boosting site, or facility level. The EPA is also finalizing as proposed the removal of the reporting requirement previously in 40 CFR 98.236(j)(2)(i)(F) that required reporting of the number of 
                        <PRTPAGE P="42137"/>
                        wells without gas-liquid separators in the basin.
                    </P>
                    <HD SOURCE="HD2">L. Flared Transmission Storage Tank Vent Emissions</HD>
                    <P>
                        The EPA is finalizing the removal of source-specific calculation and reporting of flared emissions from transmission storage tanks (renamed “condensate storage tanks” as described in section III.C.1. of this preamble). The EPA received only minor comments regarding the revisions for condensate storage tanks. See the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
                    </P>
                    <P>As discussed in the proposal preamble, the EPA determined that including flared emissions from condensate storage tank vents in the group of “other flared sources” instead of continuing to report source-specific flared emissions from transmission tanks will not affect data quality or accuracy, nor will it significantly impact the EPA's knowledge of the industry sector, emissions or trends. Therefore, consistent with section II.C. of this preamble, the EPA is finalizing as proposed the removal of both the current requirements in 40 CFR 98.233(k)(5) that require reporters to calculate flared tank vent stack emissions from this source separately from all other flared emissions at the facility and the current associated reporting requirements at 40 CFR 98.236(k)(3). Instead, the final amendments, as proposed, require data for streams from condensate storage tanks to be included in the calculation of total emissions from a flare according to 40 CFR 98.233(n)(1) through (9), and the flared condensate storage tank emissions are classified with all “other” flared sources under the flare disaggregation requirements at 40 CFR 98.233(n)(10). Similarly, the EPA is finalizing as proposed the reporting of flared condensate storage tank emissions as part of the total emissions from the flare in 40 CFR 98.236(n)(16) through (18) and as part of the disaggregated “other flared sources” emissions in 40 CFR 98.236(n)(19).</P>
                    <HD SOURCE="HD2">M. Associated Gas Venting and Flaring</HD>
                    <HD SOURCE="HD3">1. Summary of Final Amendments</HD>
                    <P>
                        The EPA is finalizing changes to associated gas venting and flaring largely as proposed. More specifically, we are finalizing changes to 40 CFR 98.233(m)(3) that require a reporter measuring the flow of natural gas to a vent using a continuous flow measurement device to use the measured flow volumes to calculate the volume of gas vented, consistent with section II.B. of this preamble. If the reporter does not use a continuous flow measurement device, the reporter must calculate emissions from associated gas using equation W-18. As proposed, we are finalizing clarifying language for the data input, volume of gas sent to sales (SGp), when using equation W-18. The volume of gas sent to sales includes gas used for other purposes at the facility site, including powering engines, separators, safety systems and/or combustion equipment and not flared or vented. The final rule, as proposed, also clarifies that reporters using equation W-18 use the volume of gas sent to sales and the volume of oil produced as inputs into equation W-18 only during periods when associated gas is vented or flared. These changes will improve the accuracy of data collected for venting and flaring associated gas. The final rule also includes changes from proposal to 40 CFR 98.233(m) to clarify, consistent with the intent of the proposed rule, that the use of measured gas flow (in lieu of equation W-18) is not optional if reporters use a continuous flow measurement device. We are finalizing the corresponding reporting requirements in 40 CFR 98.236(m)(7) to include, as proposed, a requirement to indicate whether a continuous flow monitor was used to measure flow rates and a continuous composition analyzer was used to measure CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                         concentrations. For vented wells, we are also finalizing as proposed the requirement to report the flow-weighted mole fractions of CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                         and the total volume of associated gas vented from the well, in standard cubic feet for all wells whether using GOR or continuous flow measurement devices.
                    </P>
                    <P>Consistent with treatment of flaring emissions in other sources and as proposed, the EPA is finalizing calculation of flared associated gas emissions under 40 CFR 98.233(n), Flare Stacks, with some data elements for flaring associated gas continuing to be reported under 40 CFR 98.236(m) and others under 40 CFR 98.236(n). However, as further discussed in section III.N. of this preamble, under certain circumstances, the final rule provisions allow reporters to use equation W-18 to determine inputs to the 40 CFR 98.233(n) flared associated gas emission calculations. More specifically, reporters determine gas flow volumes routed to flares using continuous parameter monitoring systems as specified in 40 CFR 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and determine gas composition using continuous gas composition analyzers or gas sampling as specified in 40 CFR 98.233(n)(4). If the reporter does not use continuous flow measurements, the reporter must calculate natural gas emissions for associated gas routed to the flare using the calculation methods in 40 CFR 98.233(m) as specified in 40 CFR 98.233(n)(3)(ii)(B).</P>
                    <P>We are also finalizing several reporting requirements from the proposal in 40 CFR 98.236(m). The volume of oil produced and the volume of gas sent to sales reported in 40 CFR 98.236(m)(5) and (6), respectively, when using equation W-18 are limited to the volumes produced and sent to sales during periods when associated gas is vented or flared. Further, as proposed, 40 CFR 98.236(m)(6) is finalized to clarify that the volume of gas sent to sales includes volumes of gas used on-site during periods when associated gas is vented or flared. Finally, we are finalizing the rule as proposed to specify that reporters do not report equation W-18 inputs if they calculate volumetric emissions from associated gas venting and flaring using a continuous flow measurement device rather than using equation W-18. These equation W-18 data elements include the GOR, the volume of oil produced, and the volume of gas sent to sales for wells with associated gas venting or flaring.</P>
                    <HD SOURCE="HD3">2. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to associated gas venting and flaring.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters strongly supported the EPA's proposal to require operators to measure the volume of associated gas sent to flares using flare stack methodologies instead of a GOR contending that use of GOR is problematic, because gas production varies by large factors over time scales from minutes to years.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA acknowledges that GOR can and does change, especially over longer time horizons. This is expected as oil and gas production leads to changing reservoir properties resulting in changes to production quantities and GORs. At production sites, GOR is often determined through a well test where produced oil and gas are routed to a test separator for a specified period of time. Oil and gas volumes are metered off the separator to determine a value for GOR.
                        <PRTPAGE P="42138"/>
                    </P>
                    <P>In finalizing today's rule, the EPA believes that direct measurement provides values for gas flow and composition with the highest degree of confidence. We are, therefore, finalizing the calculation methods in 40 CFR 98.233(m) to require that reporters use measured data in calculating and reporting emissions from associated gas venting and flaring if gas flow rates are metered in addition to the existing requirements, which are not changing with this action, that gas composition be determined through use of continuous gas composition analyzers if these are available. Although we proposed that equation W-18 would only be allowed for calculating vented emissions, we recognize based on public comment that measurement may not always be possible due to operational practices, site health and safety protocols, equipment failure, or for other reasons. As such, we are finalizing the rule today allowing use of equation W-18 in instances where direct measurement data are not available for either venting or flaring of associated gas. It is essential that reporters have access to an alternative methodology that supports accurate calculation of emissions from associated gas venting and flaring. The final rule also addresses two factors that may have impacted the accuracy and verification of reported emissions in previous years when using equation W-18. The EPA, as discussed elsewhere in this section, is finalizing the rule to require reporting of associated gas emissions and other data elements at the well level. Under the existing rule, facilities are required to report one average GOR value across all associated gas wells in the sub-basin. Although equation W-18 currently requires the use of a well-specific GOR for each well when calculating emissions, it is possible that some reporters may have used the average GOR value when calculating emissions for each well rather than the well-specific GOR. Well-level reporting with well-specific GOR will allow the EPA to verify that associated gas emission calculations are being performed correctly using well-specific GOR values, and we are finalizing this requirement in this action. The final rule also specifies that, as proposed, the volume of oil produced and the volume of gas sent to sales are only calculated during the period when associated gas is vented or flared.</P>
                    <P>
                        <E T="03">Comment:</E>
                         The EPA received comments supporting use of continuous flow measurement as an alternative to equation W-18 to calculate emission from associated gas and venting, stating that flexibility is key for many owners and operators and reflects the diversity in resources available to an owner or operator and the location and nature of its assets. One commenter noted that it may be challenging to accurately measure extremely low volumes or variable volumes of gas.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA acknowledges the commenter's support for the proposed calculation methods for associated gas venting but is clarifying the intent. As stated in section III.M. of the preamble to the 2023 Subpart W Proposal and specified in the proposed regulatory text, was to require reporters to use the measured data if they used a continuous measurement device. Specifically, the preamble to the proposed rule stated, “For associated gas venting emissions, we are proposing provisions in 40 CFR 98.233(m)(3) to specify that if the reporter measures the flow to a vent using a continuous flow measurement device the reporter must use the measured flow volumes to calculate the volume of gas vented rather than using equation W-18.” (88 FR 50332; August 1, 2023). Further, the EPA proposed the following regulatory text in 40 CFR 98.233(m)(3) establishing this requirement, “Estimate venting emissions using equation W-18 of this section. Alternatively, if you measure the flow to a vent using a continuous flow measurement device, you must use the measured flow volumes to calculate vented associated gas emissions.” (88 FR 50397; August 1, 2023). Therefore, the proposal intended equation W-18 to only be available to calculate vented associated gas emissions if the reporter does not use a continuous measurement device. Although we believe the intent was clear, given the “if you . . . you must . . .” language, we are further clarifying the provision in the final rule such that it does not use the term “alternatively” and additionally changing the order of the wording to first state that a reporter using a continuous flow measurement device must use the measured flow volumes to calculate emissions, and then state if the reporter does not use a measured flow measurement device, then equation W-18 must be used.
                    </P>
                    <P>Regarding the comments requesting flexibility with emphasis on measurement of low flows and variability of flow, the EPA acknowledges that gas flow rates during production can be variable. We disagree, though, that it will be challenging to measure gas flow at low flow rates. Flow meters used at production sites are capable of measuring very low flow rates, even to less than 1,000 cubic feet per day depending on pipe diameter. We agree, however, that variability in flow can present a challenge to operators when measuring gas flow rates using orifice meters. Flow rates that exceed the flow capacity of an orifice cross section will necessitate change out of the orifice plate. This can be challenging in cases with highly variable flow over short periods of time due to the labor, time and equipment required to replace the orifice plate at high frequency. Reporters anticipating or experiencing high variability in flow may consider using flow meters that are designed to manage the variability. If this is not possible or reporters do not elect to do so, reporters may use equation W-18 to calculate emissions from associated gas venting and flaring.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Most commenters supported not requiring the submission of equation W-18 inputs if the equation is not used to calculate emissions from venting associated gas. However, one commenter suggested that it should be clearer that if equation W-18 is used, then reporters must report those data elements.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA acknowledges the support for the proposed rule. While the EPA agrees that under the final rule reporters do not report equation W-18 inputs if they calculate volumetric emissions from associated gas venting and flaring using a continuous flow measurement device rather than using equation W-18, the EPA disagrees that further clarification of the rule language is needed. The EPA is finalizing 40 CFR 98.236(m)(4) through (6) as proposed, which requires that each data element be reported unless the reporter did not use equation W-18 to calculate associated gas venting or flaring emissions.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         A reporter sought clarification if the EPA is asking for reporters to measure the amount of gas vented when bleeding pressure off a well, stating that this would not be practical as it would require many operational units to add flow measurement devices for many day-to-day operations that scarcely ever vent, possibly only a couple times a year. The commenter further noted that this would require every pulling unit in the basin to add a flow meter, and composition analyzer. They would be required to record and track this data daily and report to the operator.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The primary purpose in bleeding pressure off a well is to allow for safe work on the well. Natural gas that is bled off an oil well is considered associated gas because the natural gas being vented is associated with oil production. Although the EPA recognizes these are often short duration events, often just a few minutes, a bleed 
                        <PRTPAGE P="42139"/>
                        off produces GHG emission at a well site if the gas is vented or flared. Multiple well bleeding events at a well site could result in sizeable emissions depending on the duration of the events. Generally, vented emissions from well bleed offs at oil wells should be included in reported associated gas emissions for the well. However, there may be instances where emissions from bleeding a well are reported under a different source, most likely completions and workovers without hydraulic fracturing. For example, the commenter references pulling units. Pulling units are often used at production pads to perform well workovers. If so, emissions associated with bleeding the well are considered to be from the workover. Emissions for this event would be calculated and reported under the Completions and Workovers without Hydraulic Fracturing source using the calculation methods in 40 CFR 98.233(h) and 98.236(h). Regardless, the EPA emphasizes that the final rule does not require reporters venting associated gas to place a flow meter on a vent line from the well as suggested by the commenter. As proposed, the EPA is finalizing the calculation methods for associated gas venting and flaring to require use of measured data when reporters measure the gas flow rate. If flow rates are not measured, reporters can use equation W-18 to calculate emissions from associated gas venting, including well bleeding events.
                    </P>
                    <HD SOURCE="HD2">N. Flare Stack Emissions</HD>
                    <P>
                        Flare stacks are an emission source type subject to emissions reporting by facilities in seven of the ten industry segments in the Petroleum and Natural Gas Systems source category.
                        <SU>52</SU>
                        <FTREF/>
                    </P>
                    <FTNT>
                        <P>
                            <SU>52</SU>
                             Flare stacks are an emission source type currently subject to emissions reporting by facilities in the following industry segments: Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, LNG Import and Export Equipment, and LNG Storage.
                        </P>
                    </FTNT>
                    <P>
                        The EPA is finalizing changes to the flared emissions calculation methodologies and the flare data reporting requirements for both the flared emissions from each source type and for each flare with modifications from the proposed amendments, as discussed in the following sections. The final changes will align the flared emissions calculation methodology and reporting with the directives in CAA section 136(h) that reported emissions be based on empirical data and accurately reflect the total CH
                        <E T="52">4</E>
                         emissions from each facility, consistent with section II.B. of this preamble. We are also finalizing changes to clarify specific provisions.
                    </P>
                    <HD SOURCE="HD3">1. Calculation Methodology for Total Emissions From a Flare</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>The EPA is finalizing several revisions to the flare emission calculation methods to improve the quality and accuracy of the calculated and reported data. Additionally, after consideration of public comments, the final requirements include several revisions from the proposal as well as some minor clarifications and other enhancements.</P>
                    <P>
                        First, we are finalizing several revisions to requirements for determining both the destruction efficiency and the combustion efficiency to use in calculating emissions from flares. The current rule and the proposal both specify only combustion efficiencies. However, after consideration of comments and consistent with section II.B. of this preamble, we are finalizing requirements to use destruction efficiencies for calculating CH
                        <E T="52">4</E>
                         emissions and to use combustion efficiencies for calculating CO
                        <E T="52">2</E>
                         emissions. Consistent with previous EPA determinations 
                        <SU>53</SU>
                        <FTREF/>
                         and regulations such as the National Emission Standards for Hazardous Air Pollutants From Petroleum Refineries (40 CFR part 63, subpart CC) (hereafter referred to as “NESHAP CC”), the final amendments specify that combustion efficiency is 1.5 percent lower than the destruction efficiency (
                        <E T="03">e.g.,</E>
                         if the destruction efficiency is 95 percent, then the corresponding combustion efficiency is 93.5 percent). Consistent with CAA section 136(h), we are finalizing as proposed a tiered approach to setting a range of default efficiencies that provide higher defaults when supported by data from the reporter implementing certain flare monitoring procedures, in 40 CFR 98.233(n)(1). As noted by commenters, the default efficiency values in the proposal were incorrectly identified as combustion efficiencies; the final rule retains the default values and correctly identifies them as destruction efficiencies. In addition, the final amendments add corresponding default combustion efficiencies that are 1.5 percent lower than the default destruction efficiencies, which will result in more accurate estimates of CO
                        <E T="52">2</E>
                         emissions. Specifically, the final default destruction efficiency and combustion efficiency are 98 percent and 96.5 percent, respectively, for Tier 1, 95 percent and 93.5 percent, respectively, for Tier 2, and 92 percent and 90.5 percent, respectively, for Tier 3. We are finalizing as proposed that the default Tier 1 efficiencies are appropriate and allowed where the reporter follows specified procedures in NESHAP CC to ensure such efficiencies are accurate.
                    </P>
                    <FTNT>
                        <P>
                            <SU>53</SU>
                             See 
                            <E T="03">Parameters for Properly Designed and Operated Flares</E>
                            , USEPA Office of Air Quality Planning and Standards. April 2012. Available at 
                            <E T="03">https://www3.epa.gov/airtoxics/flare/2012flaretechreport.pdf</E>
                             and in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        Note that the definitions of flare in subpart W and in NESHAP CC are not the same. In subpart W, a flare is defined as “a combustion device, whether at ground level or elevated, that uses an open or closed flame to combust waste gases without energy recovery.” In NESHAP CC, the flare definition does not include combustion devices with an enclosed combustion chamber (
                        <E T="03">i.e.,</E>
                         a closed flame). Thus, the requirements in NESHAP CC are different for “enclosed combustion devices” and for “open” flares. The final subpart W Tier 1 requirements recognize this difference in the NESHAP CC combustion device requirements. Specifically, for enclosed combustion devices that are utilizing the Tier 1 efficiencies, subpart W requires that the applicable testing procedures specified in 40 CFR 63.645 are followed, as well as the applicable monitoring procedures in 40 CFR 63.644. For combustion devices that use an open flame, the applicable requirements specified in 40 CFR 63.670 and 40 CFR 63.671 of NESHAP CC must be followed. In addition, for either enclosed combustors or open flares, subpart W Tier 1 requires that the applicable records in 40 CFR 63.655 are maintained to demonstrate that the NESHAP CC testing and monitoring requirements are being followed. While subpart W cross-references the NESHAP CC requirements, sources utilizing Tier 1 are not affected sources that are subject to NESHAP CC.
                    </P>
                    <P>
                        The proposed rule did not specify how to address situations where an owner or operator is utilizing the Tier 1 default efficiency but fails to meet the testing and monitoring requirements (cross-referencing certain requirements in NESHAP CC). Examples of “failing to meet the testing and monitoring requirements” would include, but not be limited to, instances where monitoring data was not collected for 75 percent of the operating hours in a day, instances where the monitoring parameters were outside of the established parameter ranges, and instances where the required visible emissions testing was not performed. Similarly, during periods when the applicable 40 CFR 63.644, 63.645, 
                        <PRTPAGE P="42140"/>
                        63.670 and 63.671 requirements are not being met, it generally would not be appropriate to continue to assume 98 percent destruction efficiency (and 96.5 percent combustion efficiency). The EPA considered requiring that the Tier 3 default efficiencies be applied any time these requirements are not being met. However, the EPA recognizes that there could be short-term episodes where one or more of the required parameters are not being met, and such an immediate requirement would require frequent oscillations between applying the Tier 1 and Tier 3 default efficiencies. The EPA concluded that this would be difficult to implement and would likely be burdensome for owners and operators. The EPA evaluated durations that would be appropriate to require switching to the Tier 3 default to ensure accuracy of total emissions reported. While NESHAP CC specifies a 45-day timeframe for allowing owners and operators to correct various types of problems, for subpart W regulations the purpose of the requirements is ensuring accurate total emissions reporting through the appropriate use of the different tiers of default destruction/combustion efficiencies. Therefore, for the final rule, the EPA selected a 15-day time frame such that, if one or more of the specific NESHAP CC testing and monitoring requirements that apply in the Tier 1 requirements are not met for 15 consecutive days, the owner or operator must apply the Tier 3 default efficiency from the time the requirement was initially not met (
                        <E T="03">i.e.,</E>
                         at the beginning of the 15 days) until such time that all requirements are being met once again. At that time, the Tier 1 default efficiencies could be applied going forward. The concept of applying different flare efficiencies based on operating conditions is similar to adjusting the flare emissions to account for periods when the flare is unlit and thus, appropriately accounting for times when the flare is not achieving any emission reduction (
                        <E T="03">i.e.,</E>
                         zero combustion efficiency). We expect that the 15-day grace period will have a minimal impact on overall reported emissions because we expect most periods when a reporter fails to meet the testing and monitoring requirements will be short. The 15-day grace period is intended to capture significant periods when the testing and monitoring requirements are not met (
                        <E T="03">i.e.,</E>
                         a 15-day grace period for a continuously operated flare would be 4.1 percent of the total operating hours).
                    </P>
                    <P>Similarly, we are finalizing as proposed that the default Tier 2 efficiencies are appropriate and allowed if the reporter follows the requirements that ensure such efficiencies are accurate, and that such requirements under subpart W are consistent with the procedures specified in NSPS OOOOb corresponding to a 95 percent destruction efficiency (as cross-referenced in the subpart W final regulations). As discussed above, the final rule also includes the default combustion efficiency of 93.5 percent. Owners and operators of sources that are subject to NSPS OOOOb can utilize the Tier 2 efficiencies by complying with the requirements. In addition, owners and operators that are not subject to NSPS OOOOb can elect to follow the cross-referenced requirements. Note that, as discussed above for NESHAP CC, voluntarily following the NSPS OOOOb requirements in order to claim the subpart W Tier 2 default efficiencies will not make the sources affected facilities under NSPS OOOOb. While the proposed Tier 2 requirements cross-referenced only the specific section in proposed NSPS OOOOb that contained the monitoring requirements contained in 40 CFR 60.5417b, the final rule includes additional requirements from those proposed, through a more comprehensive cross-reference incorporation of relevant requirements in NSPS OOOOb. As with NESHAP CC, the definition of flare in NSPS OOOOb does not include enclosed combustors and there are separate requirements for enclosed combustors and open flares. NSPS OOOOb requires that enclosed combustors be tested to demonstrate 95 percent destruction efficiency, but includes the option for owners and operators to use combustors initially tested by the manufacturer (rather than to perform the initial test on-site). The final subpart W recognizes the different NSPS OOOOb requirements for these three types of combustion devices and includes cross-references accordingly. Specifically, for enclosed combustion devices tested on-site, the requirements in 40 CFR 60.5412b(a)(1) are cross-referenced, along with testing requirements in 40 CFR 60.5413b, and the continuous compliance and continuous monitoring requirements in 40 CFR 60.5415b(f) and 60.5417b, respectively. For enclosed combustion devices tested by the manufacturer in accordance with 40 CFR 60.5413b(d), the final subpart W Tier 2 requires that the NSPS OOOOb requirements in 40 CFR 60.5413b(b)(5)(iii) and (e) and the applicable continuous compliance and continuous monitoring requirements in 40 CFR 60.5415b(f) and 40 CFR 60.5417b, respectively, are met. Finally, for open flares, the final rule requires that the NSPS OOOOb requirements in 40 CFR 60.5412b(a)(3) be followed, along with the applicable continuous compliance and continuous monitoring requirements in 40 CFR 60.5415b(f) and 40 CFR 60.5417b, respectively. For all three types, the final rule requires that the applicable records required by 40 CFR 60.5420b(c)(11) be maintained to demonstrate that the testing, monitoring procedures are being followed.</P>
                    <P>The EPA recognizes that many oil and gas sources that are not subject to NSPS OOOOb will be subject to an approved state plan or applicable Federal plan in 40 CFR part 62 that includes similar requirements to NSPS OOOOb to ensure that flare/combustion device destruction efficiency of 95 percent is met. For such sources, compliance with such an approved state plan or applicable Federal plan in 40 CFR part 62 allows the use of the Tier 2 efficiencies, provided that the requirement is a 95 percent reduction in methane emissions.</P>
                    <P>As with Tier 1, if owners and operators fail to meet one or more of the Tier 2 requirements for 15 consecutive days, the Tier 3 default efficiencies must be used until such time that all requirements are again met. Examples of failing to meet the Tier 2 requirements include, but are not limited to, when the average value of a monitoring parameter is above the maximum, or below the minimum, operating parameter, when monitoring data are not available for at least 75 percent of the hours in an operating day, when the visible emission testing results in visible emissions in excess of 1 minute in any 15 minute period.</P>
                    <P>Note that sources that are subject to either NSPS OOOOb or an approved state plan or applicable Federal plan in 40 CFR part 62 are allowed to voluntarily “step up” to Tier 1 and thus use the 98 percent destruction efficiency and 96.5 percent combustion efficiency default values.</P>
                    <P>We are also finalizing as proposed that Tier 3 applies if neither Tier 1 nor Tier 2 requirements are met. Additionally, the final Tier 3, as proposed, would apply before the flare owner or operator has implemented the relevant monitoring that would be required to comply with NESHAP CC, NSPS OOOOb or an approved state plan or applicable Federal plan in 40 CFR part 62.</P>
                    <P>
                        After consideration of public comments and consistent with section II.B. of this preamble, we are also finalizing several additional changes from the proposed flare efficiency 
                        <PRTPAGE P="42141"/>
                        requirements. One of the new final provisions is an option that allows reporters to use destruction and combustion efficiencies different than the default values when they elect to use an alternative test method that has been approved under 40 CFR 60.5412b(d) of NSPS OOOOb. The alternative test method must directly measure combustion efficiency, and the procedures in 40 CFR 60.5415b(f)(1)(x) and (xi) and 40 CFR 60.5417b(i) must be met, as well as all conditions in the monitoring plan prepared in accordance with 40 CFR 60.5417b(i)(2).
                    </P>
                    <P>
                        The final amendments also include a new option that applies to enclosed combustion devices (a subset of flares in subpart W). Specifically, as an alternative to conducting a performance test following the procedures in NSPS OOOOb, the final amendments to this subpart allow a reporter to conduct a performance test using EPA Other Test Method 52 (OTM-52, 
                        <E T="03">Method for Determination of Combustion Efficiency from Enclosed Combustors Located at Oil and Gas Production Facilities,</E>
                         dated September 26, 2023, for enclosed combustion devices that are not required to comply with NSPS OOOOb or an approved state plan or applicable Federal plan in 40 CFR part 62. This method determines combustion efficiency, whereas the test method specified in NSPS OOOOb determines destruction efficiency. Thus, the final amendments specify that when an OTM-52 test results in a combustion efficiency greater than 93.5 percent, then the reporter may use the default destruction and combustion efficiencies of Tier 2.
                    </P>
                    <P>Second, for all flares, regardless of the tier discussed previously in this section, we are finalizing requirements, mostly as proposed, to determine the presence of a pilot flame or combustion flame. The final amendments, like the proposed amendments, require either continuous monitoring (40 CFR 98.233(n)(2)(i)) or visual inspection at least once per month (40 CFR 98.233(n)(2)(ii)) for the presence of pilot flame or combustion flame. However, the final amendments include a statement specifying that the visual inspection option is allowed only when the facility complies with the Tier 3 efficiency or an approved alternative test method that does not include continuous monitoring for the presence of a flame. This statement does not change the intent of the pilot monitoring requirements since proposal. We added this statement to clarify that facilities subject to or electing to comply with the Tier 1 or Tier 2 efficiencies must comply with the continuous monitoring for the presence of a pilot flame or combustion flame as specified in the cross-referenced NESHAP CC or NSPS OOOOb, respectively, as proposed. After consideration of public comment, the following new requirements are also included in the final amendments. The final amendments include an option to use either video surveillance or advanced remote monitoring methods as examples of acceptable continuous monitoring devices that may be used. The final amendments also explicitly allow multiple or redundant monitoring devices and require either a visual inspection of the flame or a check of output from a video surveillance system whenever there is a discrepancy between the monitoring devices to assess which monitoring device is providing inaccurate readings. We are finalizing as proposed the requirement that continuous monitoring devices must monitor for the presence of a pilot flame or combustion flame at least once every 5 minutes. We are also including an additional provision in the final amendments (40 CFR 98.233(n)(2)(iii)) to clarify that any screening conducted using an alternative technology under NSPS OOOOb that detects an unlit flare and is confirmed by a ground survey constitutes a pilot flame inspection under subpart W, and the results of such surveys, together with all other monitoring and inspections that determine the flare is unlit, must be used to calculate both the time the flare was unlit during the year and the fraction of total gas routed to the flare during periods when it was unlit.</P>
                    <P>
                        Third, we proposed a requirement to use a continuous parameter monitoring system to determine either total flow volume at the inlet to the flare or the volumes for each stream from individual sources that is routed to the flare. Use of a continuous parameter monitoring system would require flow determination based on direct measurement using a flow meter if one is present or indirect calculation of flow using other parameter monitoring systems combined with engineering calculations, such as line pressure, line size, and burner nozzle dimensions. After consideration of public comments, we are not finalizing this proposed requirement and are instead finalizing requirements that are comparable to requirements for determining flow in the current rule. Currently, under 40 CFR 98.233(n)(1), if a continuous flow measurement device is used on part or all of the gas routed to the flare, then the measurement data must be used in the calculation of emissions from the flare. For the portion of gas not measured by a continuous flow measurement device, the reporter currently may estimate the flow using engineering calculations based on process knowledge, company records, and best available data. To calculate flared emissions from individual source types, the current rule specifies that flow from the source to the flare be determined using simulations (for dehydrators and storage tanks) or any of the engineering calculation options that are used to calculate flow of vented emissions. Our intent is that methods in the final amendments for determining flow align with the current requirements, except for the four following additional options and clarifications. First, 40 CFR 98.233(n)(3)(i) in the final amendments provides a new option for indirectly calculating total flow into the flare based on parameter monitoring systems combined with engineering calculations, such as line pressure, line size, and burner nozzle dimensions. This option is specified in NSPS OOOOb for determining flow into a flare; we have added it to the subpart W final amendments so that a reporter that uses this method to comply with NSPS OOOOb can calculate emissions under subpart W using the same data. Second, for clarity, all of the requirements for determining flow of streams from individual sources are either consolidated in, or cross-referenced from, 40 CFR 98.233(n)(3)(ii) rather than being dispersed throughout other sections of the rule. Third, new options are provided in 40 CFR 98.233(n)(3)(ii)(B)(1) to use either process simulation or engineering calculations that are specified in 40 CFR 98.233(d) for calculating flow of vented gas streams from acid gas removal units. These options were added so that a facility may use the same procedures for determining flow of streams routed to flares that are also specified for determining flow of vented streams from the same source types. Fourth, since some of the source-specific engineering calculation methods for calculating vented emissions calculate only the volume of GHG constituents in the gas stream, 40 CFR 98.233(n)(3)(ii)(B)(8) requires reporters to calculate the flow of non-GHG constituents in those streams using engineering calculations based on best available data and company records. This was not necessary in the proposed revisions since they required measurement of the total flare gas, which would include both GHG and non-GHG constituents. Finally, while reviewing a comment that recommended adding recordkeeping 
                        <PRTPAGE P="42142"/>
                        requirements, we realized that the proposed rule did not clearly convey our intent that the term “flow of gas from each source that routes gas to the flare” in proposed 40 CFR 98.233(n)(1)(ii) should include only the flow that actually enters the flare. In the final rule, 40 CFR 98.233(n)(3)(ii) specifies that closed vent system leaks and bypass volumes that are diverted from the flare should be excluded from the calculated and reported volume of gas routed to the flare and that that the closed vent system leaks and bypass volumes that are diverted directly to atmosphere must be used in the calculation and reporting of vented emissions from the applicable sources. See the comment and response on recordkeeping requirements in section III.N.1.b. of this preamble for a discussion of the applicable recordkeeping requirements under the final rule and a discussion of the requirements for closed vent system leaks and bypass volumes.
                    </P>
                    <P>
                        Fourth, we proposed a requirement that composition of either the total gas stream at the inlet to the flare or for each of the streams from individual sources that are routed to the flare be calculated using either a continuous gas composition analyzer or by collecting samples for compositional analysis at least once each quarter in which the flare operated. After consideration of public comments, we are not finalizing this proposed requirement and are instead finalizing requirements that are comparable to requirements for calculating composition in the current rule. For example, the final rule specifies that if a reporter is using a continuous gas composition analyzer on gas to the flare, then the measured data must be used in the calculation of emissions from the flare, which is consistent with 40 CFR 98.233(n)(2) of the current rule. The final rule specifies that if a continuous gas composition analyzer is not used on the total inlet stream to the flare, then typically, a reporter must determine composition of each stream routed to the flare using an option as specified in 40 CFR 98.233(u)(2), which is also consistent with the current rule. The final rule specifies that for hydrocarbon product streams routed to a flare, a reporter may use a representative composition based on process knowledge and best available data, as specified in 40 CFR 98.233(n)(2)(iii) of the current rule. The final rule specifies procedures for determining composition of emission streams from sources at onshore natural gas processing facilities that are consistent with the 40 CFR 98.233(n)(2)(ii) of the current rule, except that samples must be collected at least annually. According to 40 CFR 98.233(u)(2)(i) and (ii) of both the current and final rule, if a continuous gas composition analyzer is used at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility, then annual average GHG mole fractions developed from the measurement data must be used in flared emissions calculations. Other options for determining GHG composition in current 40 CFR 98.233(u)(2) include using results of sample analysis, use of default values, or use of site-specific values based on engineering estimates, depending on the industry segment. Another current option for determining composition of streams routed to flares from dehydrators and storage tanks is to use the results of process simulations as specified in current 40 CFR 98.233(e)(6) and (j)(5). Our intent is that methods in the final amendments for determining gas composition align with the current requirements, except for the five following additional options and requirements. First, 40 CFR 98.233(n)(4)(ii) in the final amendments provides a new option for determining composition of the combined total stream to a flare based on annual sampling and analysis as an alternative when a continuous gas analyzer is not used on the total stream to the flare. Second, for clarity, all of the requirements for determining composition of streams from individual sources are consolidated in 40 CFR 98.233(n)(4)(iii) rather than being dispersed throughout other sections of the rule. Third, new source-specific options are provided in 40 CFR 98.233(n)(4)(iii)(B)(
                        <E T="03">1</E>
                        ) to use either process simulation or quarterly sampling and analysis to determine composition of gas streams routed to a flare from acid gas removal units. Fourth, since 40 CFR 98.233(u)(2) requires determination of only the GHG composition, 40 CFR 98.233(n)(4)(iii)(B)(
                        <E T="03">7</E>
                        ) specifies that composition of ethane, propane, butane, and pentanes plus (for use in equation W-20 to calculate flared CO
                        <E T="52">2</E>
                         emissions) must be determined using a representative composition based on process knowledge and best available data. Fifth, when determining composition based on analysis of grab samples in accordance with 40 CFR 98.233(u)(2)(i), the final amendments (40 CFR 98.233(n)(4)(iii)) require that the samples must be collected and analyzed annually, rather than the current requirement in 40 CFR 98.233(u)(2)(i) to use “your most recent available analysis.” This change aligns the sampling frequency of individual streams with the sampling frequency specified in the final sampling option for the inlet stream to the flare as discussed previously and is expected to improve data quality and the accuracy of total reported emissions by eliminating the use of outdated data.
                    </P>
                    <P>
                        Fifth, for clarity, we are finalizing as proposed additional requirements in 40 CFR 98.233(n)(5) to specify how flow and composition data must be used to calculate total emissions depending on different scenarios a reporter could use to determine the flow and gas composition. The final 40 CFR 98.233(n)(5)(i) specifies that if both flow and gas composition are determined for the inlet gas to the flare, then these data are to be used in a single application of equations W-19 and W-20 to calculate the total emissions from the flare. If the flow and gas composition are determined for each of the streams that are routed to the flare, then one of the final options in 40 CFR 98.233(n)(5)(iii) requires the reporter to use each set of stream-specific flow and annual average concentration data in equations W-19 and W-20 to calculate stream-specific flared emissions for each stream, and then sum the results from each stream-specific calculation to calculate the total emissions from the flare. Alternatively, 40 CFR 98.233(n)(5)(iii) allows reporters to sum the flows from each source to calculate the total gas flow into the flare and use the source-specific flows and source-specific annual average concentrations to determine flow-weighted annual average concentrations of CO
                        <E T="52">2</E>
                         and hydrocarbon constituents in the combined gas stream into the flare. The calculated total gas flow and the calculated flow-weighted annual average concentrations would then be used in a single application of both equation W-19 and W-20 to calculate the total emissions from the flare. If flow is determined for all of the individual source streams while gas composition is determined for the combined stream into the flare, then 40 CFR 98.233(n)(5)(ii) requires the reporter to sum the individual source flows to calculate the total flow into the flare. This summed volume and the gas composition determined for the combined stream into the flare would be used in a single application of equations W-19 and W-20 to calculate the total emissions from the flare. Finally, 40 CFR 98.233(n)(5)(iv) specifies that a reporter may not calculate flared emissions based on the determination of 
                        <PRTPAGE P="42143"/>
                        the total volume at the inlet to the flare and gas composition for each of the individual streams routed to the flare. This combination of volume and gas composition determinations is not allowed because there is no way to calculate flow-weighted average compositions of either the inlet gas to the flare or the individual source streams.
                    </P>
                    <P>
                        Sixth, we are finalizing as proposed to delete the option to use a default higher heating value (HHV) in the calculation of N
                        <E T="52">2</E>
                        O emissions and instead require all reporters to use either a flare-specific HHV or individual flared gas stream-specific HHVs in the calculation. In the existing rule, 40 CFR 98.233(n)(7) requires the use of equation W-40 to calculate N
                        <E T="52">2</E>
                        O emissions from flares. This equation requires the flared gas volume, the HHV of the flared gas, and the use of a default emission factor. For field gas or process vent gas, the variable definition for the HHV provides that either a site-specific or default value may be used; for other gas streams, a site-specific HHV must be used. We are finalizing as proposed in 40 CFR 98.233(n)(8) to require the use of a flare-specific HHV when composition of the inlet gas to the flare is measured or when flow-weighted concentrations of the inlet gas are calculated from measured flow and composition of each of the streams routed to the flare. Similarly, final amendments require reporters to calculate N
                        <E T="52">2</E>
                        O emissions using flared gas stream-specific HHVs when flow and composition are determined for each of the individual streams that are routed to the flare and emissions are calculated per stream and summed to calculate total emissions from the flare. A change from the proposal is that the final rule also allows the direct measurement of the HHV as an alternative to calculation of the HHV from the composition information. This measurement can be conducted at the inlet to the flare or measurements may be made for each stream and be used in conjunction with the flow estimates for each stream to calculate a weighted annual average HHV. We also finalized as proposed a new requirement in 40 CFR 98.236(n)(9) to report the HHV(s) used to calculate N
                        <E T="52">2</E>
                        O emissions. This data element will improve verification of reported N
                        <E T="52">2</E>
                        O emissions and minimize the amount of communication with reporters via e-GGRT. It also will be useful for characterizing the differences in flared gas streams among the various industry segments and basins, and it is expected to be useful in analyses such as updates to the U.S. GHG Inventory.
                    </P>
                    <P>
                        Seventh, we are finalizing as proposed the changes to the emission calculation requirements for flares that use CEMS because the existing methodology to calculate total GHG emissions when using CEMS is inconsistent with CAA section 136(h) as described in section II.B. of this preamble. Currently, if a reporter operates and maintains a CEMS to monitor emissions from a flare, existing 40 CFR 98.233(n)(8) requires the reporter to calculate only CO
                        <E T="52">2</E>
                         emissions from the flare. The final amendments revise existing 40 CFR 98.233(n)(8) (final 40 CFR 98.233(n)(9)) to require reporters to comply with all of the other emission calculation procedures as proposed in 40 CFR 98.233(n), with one exception. The exception is that since CO
                        <E T="52">2</E>
                         emissions are measured with the CEMS, calculation of CO
                        <E T="52">2</E>
                         emissions using equation W-20 is not required. We expect that these final amendments will address a potential gap in CH
                        <E T="52">4</E>
                         emissions reporting and improve the overall quality and completeness of the emissions data collected by the GHGRP, consistent with section II.A. of this preamble.
                    </P>
                    <P>
                        Eighth, we are finalizing with revisions both the removal of the current source-specific methodologies for calculating flared emissions (
                        <E T="03">i.e.,</E>
                         existing 40 CFR 98.233(e)(6) for dehydrators, existing 40 CFR 98.233(g)(4) for completions with hydraulic fracturing, existing 40 CFR 98.233(h)(2) for completions without hydraulic fracturing, existing 40 CFR 98.233(j)(5) for tanks, existing 40 CFR (l)(6) for well testing, and existing 40 CFR 98.233(m)(5) for associated gas) and the addition of a requirement that the reporter use engineering calculations and best available data to disaggregate the calculated total emissions per flare to the source types that routed gas to the flare (40 CFR 98.233(n)(10)). The final amendments require disaggregated emissions to be calculated using engineering calculations and best available data as was proposed; however, the revisions include a requirement that if stream-specific flow and composition for a single source type is used to calculate flared emissions then the source-specific emissions calculated using this data must be used to calculate the disaggregated emissions per source type. Disaggregating the total emissions per flare to the applicable source types that route emissions to the flare will eliminate the disconnect between the sum of source-specific flared emissions versus the total emissions per flare that has occurred under the current approach. This will improve the overall quality and accuracy of total reported emissions from the flare stacks source type, while maintaining acceptable accuracy of estimated flared emissions per source type for use in assessing trends in control over time, policy determinations carrying out provisions under the CAA, and in U.S. GHG Inventory development.
                    </P>
                    <P>Finally, we are finalizing as proposed the removal of existing 40 CFR 98.233(n)(9). Since the final amendments eliminate the source-specific flared emissions calculation methodologies, as discussed above, the requirement in existing 40 CFR 98.233(n)(9) to subtract source-specific flared emissions from the total emissions per flare is not needed to avoid double reporting of flared emissions under the final amendments.</P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to the calculation methodologies for emissions from flare stacks.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Several commenters indicated that subpart W does not properly distinguish between combustion efficiency (CE) and destruction efficiency (DE) (also known as destruction and removal efficiency [DRE]). One commenter asserted that methane emission calculations must be based on destruction efficiency, not combustion efficiency, to account for all methane oxidized whether to CO
                        <E T="52">2</E>
                         or CO. One commenter stated that the accurate method to calculate and report CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                         emissions is to use DE in equation W-19 to calculate CH
                        <E T="52">4</E>
                         emissions and to use CE in equation W-20 to calculate CO
                        <E T="52">2</E>
                         emissions. This commenter also noted that using only CE in subpart W is inconsistent with other EPA flare regulations such as 40 CFR 63.670(r). One commenter stated that the definition of the CE term in equation W-19 is equivalent to DE in the literature; according to the commenter, this inconsistency will lead to confusion for subpart W reporters because those familiar with flares calculate emissions from DE, not from CE. Another commenter asserted that the EPA must understand the distinction between CE and DE when evaluating studies and literature. Two commenters noted that the EPA should define a relationship between CE and DE. One of these commenters suggested that DE be 1.5 percent higher than CE, as in an EPA publication (“Parameters for Properly Designed and Operated 
                        <PRTPAGE P="42144"/>
                        Flares”) 
                        <SU>54</SU>
                        <FTREF/>
                         and in regulations. The other commenter summarized the results of two studies that measured and compared CE and DE for numerous flares.
                        <E T="51">55 56</E>
                        <FTREF/>
                         The commenter developed a correlation between the CE and DE data and suggested that this correlation could be used to calculate DE from measured CE or vice versa with high accuracy.
                    </P>
                    <FTNT>
                        <P>
                            <SU>54</SU>
                             
                            <E T="03">Id.</E>
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>55</SU>
                             Allen, D. and Torres, V. 
                            <E T="03">TCEQ 2010 Flare Study Final Report.</E>
                             The University of Texas at Austin. The Center for Energy and Environmental Resources. Prepared for TCEQ. August 1, 2011. Available at 
                            <E T="03">https://www.tceq.texas.gov/airquality/stationary-rules/stakeholder/flare_stakeholder.html</E>
                             and in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                        <P>
                            <SU>56</SU>
                             Providence Photonics, LLC. Comments on Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems. Data in Exhibit 1 (CBI).
                        </P>
                    </FTNT>
                    <P>
                        <E T="03">Response:</E>
                         The proposal used the term combustion efficiency because that is the term used in the existing part 98 regulations. However, we agree with the commenters that there is a difference between destruction efficiency and combustion efficiency, and we agree that destruction efficiency is the value that should be used to calculate CH
                        <E T="52">4</E>
                         emissions and combustion efficiency is the correct value to use to calculate CO
                        <E T="52">2</E>
                         emissions. Based on consideration of these comments, we have corrected the efficiency terms in equations W-19 and W-20 of the final amendments so that destruction efficiency is used in equation W-19 to calculate CH
                        <E T="52">4</E>
                         emissions and combustion efficiency is used in equation W-20 to calculate CO
                        <E T="52">2</E>
                         emissions.
                    </P>
                    <P>
                        We also agree with commenters that the default combustion efficiencies in the three proposed tiers (40 CFR 98.233(n)(4)(i) through (iii) of the proposal) are actually destruction efficiencies, and we agree that a relationship between combustion efficiency and destruction efficiency should be included in the rule. We believe the relationship in “Parameters for Properly Designed and Operated Flares” (
                        <E T="03">i.e.,</E>
                         destruction efficiency is 1.5 percent higher than destruction efficiency over the full range of destruction efficiencies) is the most appropriate relationship at this time. This relationship has a history of more than 10 years acceptance by the EPA, it is used in other regulations such as NESHAP CC, and it is simple to implement. However, we believe the correlation equation suggested by one commenter shows promise for future consideration, especially since it appears the difference between combustion efficiency and destruction efficiency increases at lower destruction efficiencies. As discussed in the response to the following comment in this section, we are finalizing with some modifications from proposal the three tiers, and after consideration of these comments and the EPA's reassessment of the terms used in the proposal, we are specifying both default destruction efficiencies that are consistent with the proposed combustion efficiencies and default combustion efficiencies that are 1.5 percent less than the default destruction efficiencies. These changes will result in more accurate emissions calculation and reporting, though we note that the calculated CO
                        <E T="52">2</E>
                         emissions will be slightly lower under the final amendments relative to emissions calculated based on the proposed methodology.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Numerous commenters strongly opposed the proposed revisions that would require reporters to calculate emissions from flares using only one of three default flare combustion efficiencies that are correlated to the type of flare monitoring that they conduct.
                        <SU>57</SU>
                        <FTREF/>
                         The commenters primary objection was that the proposed requirement to use only a default efficiency is that it does not allow reporters to use higher efficiencies that can be demonstrated based on empirical data. Commenters also asserted that reporters should not be limited to the proposed defaults because flares generally achieve destruction efficiencies of 98 percent when operating within the parameters of 40 CFR 60.18 and studies have shown that many flares achieve a destruction efficiency considerably higher than 98 percent. One commenter stated that the 95 percent emission reduction required under NSPS OOOOa and proposed under NSPS OOOOb and EG OOOOc was designed to allow operators to use other control options beyond flare combustion devices.
                    </P>
                    <FTNT>
                        <P>
                            <SU>57</SU>
                             Although the proposal specified only combustion efficiencies, some commenters referred to destruction efficiencies, consistent with their comments that are described in the preceding comment summary. In this comment summary we refer to destruction efficiencies when that is the term that was used by commenters. We use the term “efficiency” when some commenters referred to combustion efficiency and others referred to destruction efficiency.
                        </P>
                    </FTNT>
                    <P>
                        To address their objections, the commenters stated that the EPA should either replace or modify the proposed tiered system of default combustion efficiencies with various alternatives. A majority of the commenters stated that the EPA should allow reporters to use efficiencies based on manufacturer guarantees and/or to use efficiencies in existing federal or state rules that also apply to the flares. A few commenters stated that reporters should be allowed to use efficiencies consistent with the efficiencies required in federal or state operating permits or to use state-approved efficiencies for specific flare models that have been tested by the flare manufacturer. Some commenters stated that the EPA should allow the use of direct measurement of efficiencies using existing or future advanced technologies (
                        <E T="03">e.g.,</E>
                         simplified Video Imaging Spectro-Radiometry (VISR)) once the technology has been vetted by a regulatory agency. One commenter stated that the EPA should allow the use of efficiencies obtained based on direct measurement using advanced direct measurement methods that the EPA has used for inspection and compliance purposes. Two commenters stated that reporters should be allowed to use efficiencies based on the results of parametric monitoring. One of these commenters described an approach based on computational fluid dynamics data from ultrasonic flow meters that is analyzed by an artificial intelligence technique into a numerical model to calculate combustion efficiency. One commenter stated that reporters should be allowed to use efficiencies obtained from performance tests for vapor combustors, enclosed flares, and thermal oxidizers. Another commenter noted that the proposed Tier 2 did not cross-reference the NSPS OOOOb provision that allows a facility to determine compliance with NSPS OOOOb based on the results of manufacturer testing of enclosed combustion devices. Another commenter stated that reporters should be allowed to use (OTM-52) to determine destruction efficiency or combustion efficiency of enclosed combustion devices. To prevent inconsistent reporting between subpart W and other EPA programs, one commenter stated that reporters should be allowed to use a default destruction efficiency of 98 percent for flares that are designed and operated according to 40 CFR 60.18, and that a 98 percent destruction efficiency also should be allowed for other flares that are operated within New Source Review permit compliance requirements.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         Based on consideration of the comments, the proposed default combustion efficiencies (finalized as destruction efficiencies as explained in the response to the preceding comment) are being finalized as options with some changes from the proposal. An additional option is being finalized (40 CFR 98.233(n)(1)(iv)) that allows for improved alignment with the NSPS program whereby an owner or operator can use an alternative test method that 
                        <PRTPAGE P="42145"/>
                        has been submitted to and approved by the EPA under 40 CFR 60.8(b), as outlined in 40 CFR 60.5412b(d) or 60.5412c(d) to demonstrate a greater combustion efficiency based on empirical data and utilize the results to calculate flared emissions under subpart W. The submitter must demonstrate to the satisfaction of the EPA under 40 CFR 60.8(b) that the alternative test method, when implemented as presented in the request for approval, including all documented monitoring protocols, continuously demonstrates compliance with a combustion efficiency of 95 percent or greater. Under NSPS OOOOb, or a state or Federal Plan in 40 CFR part 62 implementing EG OOOOc, a submitter may demonstrate compliance either through continuous measurement of combustion efficiency or through continuous measurement of the net heating value of the combustion zone and the net heating value dilution parameter (if the flare uses perimeter assist air). Note, however, that only alternative test methods based on continuous measurement of combustion efficiency will be allowed under subpart W because the purpose of allowing the alternative test method is to enable reporters to identify specific destruction and combustion efficiencies that differ from the defaults; the option based on continuous measurement of the net heating values does not result in a specific combustion efficiency. Likewise, if the submitter is using the alternative test method to document combustion efficiencies greater than 95 percent, they would need to provide sufficient documentation for how this was determined and the uncertainties associated with the measurement. When the EPA approves an alternative test method, the approval may be site-specific or it may become broadly applicable, approved for a class of flares such that reporters for all flares meeting the requirements outlined in the alternative test method may use the actual demonstrated combustion efficiency (and an assumed destruction efficiency 1.5 percent higher than the combustion efficiency) to calculate flared emissions under subpart W, provided they also implement inspections and monitoring that are part of the approved alternative test method. This alternative provides owners and operators a pathway to gain approval to directly measure efficiency using advanced measurement technology or other methods that may be approved for a destruction efficiency higher than default values specified under the three tiers. The alternative also aligns the flare emissions calculation methodology with the directives in CAA section 136(h) that reported emissions be based on empirical data that accurately reflect the total emissions, consistent with section II.B. of this preamble.
                    </P>
                    <P>
                        We agree with the commenter that pointed out the proposed Tier 2 requirements should include a cross-reference to the applicable section in NSPS OOOOb that specifies performance test requirements for enclosed combustion devices in NSPS OOOOb (
                        <E T="03">i.e.,</E>
                         a subset of the total flare population under subpart W). This oversight has been corrected in 40 CFR 98.233(n)(1)(ii)(A) and 40 CFR 98.233(n)(1)(ii)(C) of the final amendments by including cross-references to 40 CFR 60.5413b(b) and (d) that require facilities to either conduct testing of enclosed combustion devices themselves or have testing conducted by the enclosed combustion device manufacturer. When the test demonstrates a destruction efficiency of 95 percent or greater, and monitoring parameter values, including those that must be established during the test, are within the specified ranges, then the reporter may use the Tier 2 default efficiencies.
                    </P>
                    <P>We have also evaluated the suggestion by a commenter to allow the use of OTM-52 as an alternative to the performance testing requirements in NSPS OOOOb. OTM-52 is a draft method that is less costly and easier to implement than the reference method in NSPS OOOOb. It is used to determine combustion efficiency rather than destruction efficiency. It has not been approved as an alternative to the test method in NSPS OOOOb and thus, it may not be used to test an enclosed combustion device that is subject to NSPS OOOOb. Similarly, it has not been approved as an alternative to the test method in EG OOOOc and thus, may not be used to test an enclosed combustion device that is subject to a state or Federal Plan in 40 CFR part 62 implementing EG OOOOc. However, for enclosed combustion devices that are not subject to NSPS OOOOb or state or Federal Plans in 40 CFR part 62 implementing EG OOOOc that require 95 percent reduction in methane emissions, we believe it provides an acceptable level of accuracy for the purposes of calculating emissions using the Tier 2 default efficiencies when a test results in a combustion efficiency of 93.5 percent or greater. Therefore, OTM-52 is included in 40 CFR 98.233(n)(1)(iv) of the final amendments as an alternative to the Tier 2 performance testing procedures for enclosed combustion devices that are not subject to NSPS OOOOb or a state or Federal Plan in 40 CFR part 62 implementing EG OOOOc.</P>
                    <P>
                        We have not included other methods suggested by the commenters for demonstrating flare efficiencies to use in calculating emissions under subpart W (
                        <E T="03">e.g.,</E>
                         manufacturer guarantees, presumption that operation according to 40 CFR 60.18 ensures 98 percent destruction efficiency, parametric monitoring, state-approved efficiencies, or efficiencies in permits) because we have determined that they do not provide a reasonable assurance that the stated efficiency would be continuously met or we do not have data available at this time needed to implement such methods and to verify the results. Specifically, with respect to the commenter's assertion that flares operated according to 40 CFR 60.18 should be allowed to use a 98 percent destruction efficiency, we note that the General Provisions at 40 CFR 60.18 state that the referencing subpart will specify the monitoring requirements and that 40 CFR 60.18 on its own does not ensure a properly operating flare. In the supplemental proposal to NSPS OOOOb,
                        <SU>58</SU>
                        <FTREF/>
                         we noted that recent studies suggest that 10 percent of flares in the Permian basin are either unlit or are only burning a portion of the gas sent to the flare 
                        <SU>59</SU>
                        <FTREF/>
                         and that the current operating and monitoring practices and requirements for well sites and centralized production facilities are not adequate to ensure flare control systems are operated efficiently. Therefore, under the final NSPS OOOOb provisions, we have finalized compliance requirements to ensure all aspects of the General Provisions at 40 CFR 60.18 are met at all times. These provisions are cross-referenced in subpart W to provide assurance that a 95 percent destruction efficiency is accurate for the flare. Flares that are not operated properly cannot be reasonably assured to have the claimed destruction efficiency. Without assurances that the flare is being operated properly, it is our assessment that a destruction efficiency associated with a properly functioning flare (
                        <E T="03">i.e.,</E>
                         95 percent or higher) would be inappropriate and not ensure accurate total emissions reported. Similarly, with respect to the commenter's assertion that destruction efficiencies be based on a manufacturer's guarantee, the 
                        <PRTPAGE P="42146"/>
                        guarantees alone would not ensure that the flares are being operated properly and that those destruction efficiencies accurately reflect actual operation of the flare. We expect that a 95 percent destruction efficiency will be a reasonably accurate average destruction efficiency for a properly operated flare, considering that there will be periods during which the flare is unlikely to meet a higher manufacturer claimed destruction efficiency, due to operating conditions, 
                        <E T="03">e.g.,</E>
                         high cross-winds. Therefore, at this time, we have not included additional alternative methods or destruction efficiencies. For additional comments and response on alternatives to the proposed destruction efficiencies, see section 15 of the 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                        , available in the docket to this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).
                    </P>
                    <FTNT>
                        <P>
                            <SU>58</SU>
                             See 87 FR 74793 (December 6, 2023).
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>59</SU>
                             Permian Methane Analysis Project (PermianMAP) reporting the results of 4 Environmental Defense Fund (EDF) surveys of over a thousand flare stacks from February to November 2020. See 
                            <E T="03">https://www.permianmap.org/flaring-emissions</E>
                            .
                        </P>
                    </FTNT>
                    <P>
                        <E T="03">Comment:</E>
                         Numerous commenters claimed that the proposed 92 percent destruction efficiency 
                        <SU>60</SU>
                        <FTREF/>
                         for Tier 3 was too low because the value in the cited study 
                        <SU>61</SU>
                        <FTREF/>
                         included unlit flares. According to the commenters, since emissions from unlit flares would be calculated separately under the proposal, including them in the Tier 3 destruction efficiency would result in double counting of the emissions.
                    </P>
                    <FTNT>
                        <P>
                            <SU>60</SU>
                             The proposal incorrectly stated that the 92 percent efficiency for Tier 3 was the combustion efficiency. As discussed in the response to a preceding comment, the 92 percent should be the destruction efficiency. In this comment summary we refer to the efficiency as destruction efficiency to reflect the accurate terminology.
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>61</SU>
                             Plant, G., 
                            <E T="03">et. al.</E>
                             2022. “Inefficient and unlit natural gas flares both emit large quantities of methane.” Science, 377 (6614). 
                            <E T="03">https://doi.org/10.1126/science.abq0385</E>
                            . Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        <E T="03">Response:</E>
                         Table 1 in the Plant 
                        <E T="03">et al.</E>
                         (2022) study reported both observed flare DREs and total effective DREs for flares in three basins. The total effective DREs are based on both the observed flare DREs (from lit flares) plus the percentage of unlit flares obtained from a separate study. However, the 92 percent destruction efficiency for Tier 3 is based on the mean observed flare DRE for the Permian basin rounded up from 91.7 percent to 92 percent; it is not based on the reported overall average total effective DRE of 91.1 percent. Thus, the final Tier 3 destruction efficiency of 92 percent does not double count emissions for unlit flares.
                    </P>
                    <P>We have determined that the average observed destruction efficiency of 92 percent is a reasonable combustion efficiency for subpart W sources that are not monitoring as specified under Tier 1 or Tier 2 because the overall average in the empirical results likely included many facilities with higher performing flares that would likely comply with one of those tiers and thus should be excluded from the calculation of the average for Tier 3 flares. We agree that it is important to allow for submission of empirical data, as appropriate; therefore, as discussed in the previous response, we have added an option to use that allows for improved alignment with the NSPS program whereby an owner or operator can use an alternative test method that has been submitted to and approved by the EPA under 40 CFR 60.8(b), as outlined in and 40 CFR 60.5412b(d) or 60.5412c(d). The final default destruction efficiencies and alternative option align with the directives in CAA section 136(h) that reported emissions be based on empirical data that accurately reflect the total emissions, consistent with section II.B. of this preamble.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters stated that the rule should allow monitoring of the presence of a pilot flame using visual observation with a video camera, and one commenter noted that this approach would more efficiently utilize manpower and potentially result in more timely discovery and correction of unlit or malfunctioning flares. Commenters asserted that subpart W should allow the use of auto-ignitors instead of requiring continuous pilots. They noted that states such as Texas and New Mexico allow auto-ignitors, and they pointed out that use of such devices eliminates the need for a continuous pilot, thereby reducing the amount of pilot and sweep gas needed to operate the flare. One commenter requested that the EPA allow the use of the VISR device to monitor the presence of pilot flame.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We agree that the use of video cameras and advanced remote measurement options are viable means for detecting the presence or absence of a pilot flame, and these options have been added in 40 CFR 98.233(2)(i) of the final amendments. We have not allowed the use of auto-ignitors as an alternative to maintaining a continuous pilot flame in the final amendments. In response to comments on NSPS OOOOb requesting that auto-ignitors be allowed in that rule, we explained that there is not sufficient data currently to suggest that electronic ignition systems on combustion devices are capable of continuously supplying a constant source of ignition adequate to keep a flame present on a continuous basis. Our reply to comments on NSPS OOOOb also indicated that the EPA does not have sufficient information on the degradation of electronic ignition systems or how to ensure these systems maintain functionality over time. Additionally, our reply noted that operating a flare with a continuously lit pilot adds an additional degree of flame stability to the flare itself, and we do not have sufficient information on whether the sporadic lighting of the combustion device tip would lead to flame instability, and by extension, poor combustion.
                        <E T="51">62 63</E>
                        <FTREF/>
                         We maintain these same views and assessments in this final rulemaking regarding this commenter's suggestion for the subpart W regulations. Thus, auto-ignitors are not allowed in subpart W due to the uncertainty regarding the effect they may have on the destruction efficiency and combustion efficiency of the flare.
                    </P>
                    <FTNT>
                        <P>
                            <SU>62</SU>
                             Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews 40 CFR parts 60 and 63 Response to Public Comments on Proposed Rule August 23, 2011 (76 FR 52738). P. 308. in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                        <P>
                            <SU>63</SU>
                             EPA's Responses to Public Comments on the EPA's Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources May 2016. P. 11-190. in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter recommended revising the pilot flame monitoring requirements to allow the use of multiple or redundant monitoring devices or inspection techniques. According to the commenter, monitoring device malfunctions are not uncommon and an operator should have the option to confirm whether a monitoring result is errant and not include the time as unlit if other monitoring/inspection information demonstrates the output of the device to be incorrect.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We note that the proposed amendments did not prohibit the use of multiple pilot flame monitoring devices, but we agree with the commenter that it would be appropriate to explicitly state in subpart W that this is allowed. This provision has been added in 40 CFR 98.233(n)(2)(i)(B) of the final amendments. We also included a requirement that when there is a discrepancy in the output of multiple devices that the operator must either visually confirm or use video surveillance output to confirm that the flame is present as soon as practicable after detecting the discrepancy to ensure that at least one device is operating properly. If at least one device is confirmed to be operating properly, then the operator may continue to rely on the 
                        <PRTPAGE P="42147"/>
                        properly operating device(s) for monitoring the pilot. By “discrepancy” we mean one or more devices indicate the flare is unlit while one or more other devices indicate it is lit. We do not mean cases in which two or more devices provide different output values, but all values confirm the flare is lit. For example, two thermocouples that register different temperatures, either of which confirms the flare is lit, does not constitute a discrepancy for this purpose under subpart W.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters opposed the proposed requirement to measure flow using flow meters or parameter monitoring systems combined with engineering calculations. The most commonly stated objections were that most flow meters are inaccurate on low-pressure streams and streams with low or intermittent flow that are common in the upstream and midstream industry segments, and the cost to install meters would be excessive. Commenters also noted that many flares are located at sites that lack electrical power, SCADA systems, WiFi and cellular coverage, and field offices. One commenter noted that process simulation is approved for determining flow to use in calculating vented emissions, and it seems inconsistent to disallow the same methods for determining flow to flares. One commenter asserted that field testing shows parametric monitoring overestimates flow volumes, and one commenter stated that it can be difficult to calibrate flow meters on variable flow streams.
                    </P>
                    <P>Instead of requiring continuous measurement of flow, most of the commenters recommended retaining the current requirements that require use of measurement data only when a continuous flow measurement device is used to measure total or partial flow to the flare and to allow engineering calculations based on process knowledge, company records, and best available data when flow is not measured using a continuous flow measurement device. A few commenters stated that process simulation should be allowed, particularly for streams from dehydrators and tanks. One commenter stated that engineering calculations should be allowed, particularly for blowdown events that are from equipment with defined volumes and known temperatures and pressures. One commenter recommended that the rule be revised to allow use of a remote measurement method to measure flow rate.</P>
                    <P>
                        <E T="03">Response:</E>
                         After consideration of these comments, we agree with the comments that methods that are allowed for determining flow of vented emissions should also be allowed to determine flow to a flare, that in some cases, such as for streams to low pressure flares, modeling may produce flow estimates for the purposes of estimating annual greenhouse gas emissions with accuracy similar to measurements using flow meters. We also agree with commenters that the proposal underestimated the costs of monitoring and that remote sites may not have access to grid electricity needed to power the meters and other measurement devices. Based on these considerations, the final amendments specify options for determining flow based on slightly modified versions of the proposed continuous parameter monitoring options (40 CFR 98.233(n)(1)(i) and (ii) as proposed) that align more closely with current requirements as well as new options that also are more closely aligned with options in the current rule.
                    </P>
                    <P>The proposed option to measure flow of the total inlet stream to the flare was finalized with two changes from proposal (40 CFR 98(n)(3)(i)). One change was to add a sentence specifying that measured flow must be used in calculating the flared emissions if a continuous parameter monitoring system is used. This requirement was added since the final amendments include options other than the continuous monitoring options, and a facility may not elect to calculate emissions based on one of the other options if they have measured volumes. This change is consistent with the requirements in 40 CFR 98.233(n)(1) of the current rule. The second change was to add a requirement to use engineering calculations based on best available data and company records to calculate pilot gas flow to add to the total gas flow to the flare. This requirement was added because we realized that we had inadvertently neglected to include a requirement for determining pilot gas flow in the proposal. This change also makes the final option consistent with the requirement in 40 CFR 98.233(n)(1) to determine flow for “all of the flare gas.”</P>
                    <P>The final amendments also specify several options for determining the flow of individual streams that are routed to the flare. The proposed option to use a continuous parameter monitoring system was finalized as proposed (40 CFR 98.233(n)(3)(ii)(A)), except that a sentence was added specifying that measured flow must be used in calculating the flared emissions if a continuous parameter monitoring system is used. This sentence was added for the same reason noted above for adding it to the option for using a continuous parameter monitoring system to measure total inlet flow to the flare.</P>
                    <P>
                        The final amendments also include new options to determine flow using process simulations, engineering calculations, and emission factor methods consistent with methods specified for determining vented emissions for sources whose flared emissions are required to be disaggregated. The applicable options are specified in separate paragraphs for each source type for which subpart W specifies methods for determining flow of vented emissions (40 CFR 98.233(n)(3)(ii)(B)(
                        <E T="03">1</E>
                        ) through (7)). Additionally, for source types that are subject to flare-specific reporting in the current rule (
                        <E T="03">e.g.,</E>
                         dehydrators, completions, tanks, well testing, associated gas), these options are consistent with the requirements in the current rule for determining the volume of gas routed to flares. For other source types, including new source types subject to reporting for the first time under these amendments (
                        <E T="03">e.g.,</E>
                         crankcase venting) and sources that do not have methods for calculating vented emissions in subpart W, 40 CFR 98.233(n)(3)(ii)(B)(
                        <E T="03">8</E>
                        ) of the final amendments specifies that flow to the flare may be calculated using engineering calculations based on process knowledge, company records, and best available data. Additionally, since some of the methods for calculating vented emissions calculate only the flow of GHGs, 40 CFR 98.233(n)(3)(ii)(B)(
                        <E T="03">8</E>
                        ) of the final amendments also specifies that the flow of the non-GHG portion of the streams routed to the flare also must be based on process knowledge, company records, and best available data.
                    </P>
                    <P>
                        We have not included an option in the final rule to determine flow using the VISR advanced remote sensing method suggested by one commenter because we do not have sufficient information on the applicability and effectiveness of the method for determining flow over the range of conditions expected at facilities in the oil and gas industry. The study cited in the commenter's letter evaluated the method for a single steam-assisted flare at a research facility using natural gas as the flared gas. It is not clear from this study how the method would be implemented and perform when used for other types of flares and when the flared gas includes other hydrocarbons in addition to methane and the composition varies with time. The method also provides flow only of the combustible constituents in the flared gas, which means procedures for converting to total volume would need 
                        <PRTPAGE P="42148"/>
                        to be specified in the rule so that the flow could be used to calculate emissions using equations W-19, W-20, and W-40, or the rule would need separate procedures for calculating emissions when using this method. The paper summarizing the results of the study also noted that the method is less accurate when the combustion efficiency is low. The EPA intends to further evaluate this method as additional information becomes available and may consider including an option based on this method in a future rulemaking.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter supported the proposed approach that provided a choice between using a continuous gas analyzer or conducting periodic compositional analysis. However, numerous commenters opposed the proposed composition measurement requirements for a variety of reasons. The most commonly cited reasons for opposition were that the composition of produced gas is relatively stable so frequent sampling will not significantly improve accuracy of emissions calculations and that the requirement would add significant costs and not be cost effective. Some commenters indicated that there would be logistical challenges to quarterly sampling because only a limited number of labs are capable of conducting the required analyses, and there would be logistical challenges to the use of continuous composition analyzers including installation of sample ports, calibration and maintenance of the thousands of meters, and lack of infrastructure and field connectivity. One commenter added that requiring compositional monitoring would further exacerbate ongoing COVID-related supply chain delays. Other commenters asserted that there are technical challenges to collecting samples in low-pressure lines with intermittent flows, and one commenter stated that it is difficult to calibrate composition analyzers on such streams. One commenter stated that it is inconsistent to require analysis of streams routed to flares when such analysis is not required for calculating vented emissions from the same source types. One commenter stated that sampling sour gas streams would pose a safety risk due to the presence of high H2S concentrations. One commenter objected to the proposed analysis requirements because they go beyond the continuous NHV monitoring or demonstration under proposed NSPS OOOOb and EG OOOOc. One commenter asserted that the proposed annual sampling of purge gas, sweep gas, and auxiliary fuel would pose undue burdens on operators for stream that will not significantly impact emissions reported under subpart W.
                    </P>
                    <P>Instead of requiring continuous gas composition analyzers or periodic sampling and analysis, nearly all of the commenters stated that the current requirements should be retained. Many of these commenters specifically indicated that the final rule should allow the current option to determine composition using process simulations. Other commenters stated that the final rule should include the current options for using engineering calculations, best available data, or representative sampling. Two commenters suggested that the frequency of conducting analysis of representative samples should be at least annually. If quarterly sampling is retained in the final amendments, two commenters requested that the rule also include a provision allowing companies to reduce the frequency after some period of showing that the composition is stable. One commenter stated that sales gas composition should be allowed for pilot/assist gas. Another commenter requested that the sampling of purge gas, sweep gas, and auxiliary fuel be made voluntary or required only if the volume exceeds a specified threshold.</P>
                    <P>
                        <E T="03">Response:</E>
                         After consideration of the public comments, we agree with the commenter that asserted methods allowed for determining composition of vented emissions should also be allowed to determine composition of streams routed to a flare. We also agree with commenters that the proposal underestimated the costs of monitoring. Based on these considerations, the final amendments include additional options for determining composition based on process simulation and engineering calculations as well as the continuous gas composition monitoring and periodic sampling and analysis options that are finalized with some changes from proposal.
                    </P>
                    <P>The final amendments include two options for determining composition of the total inlet stream to the flare that include some changes from proposal (40 CFR 98.233(n)(3)(i) and (ii)) as proposed). One option, in 40 CFR 98.233(n)(4)(i) of the final amendments, finalizes the proposed option to use a continuous gas composition analyzer on the total inlet stream to the flare. As in the current rule, the final amendments specify that measured compositions must be used in calculating emissions when a continuous gas composition analyzer is used. The second option, to conduct quarterly sampling and analysis of the total inlet stream to the flare, is finalized in 40 CFR 98.233(n)(4)(ii) with several changes from proposal. One change is that the minimum sampling frequency is reduced to once per year. A second change is the proposed requirement to calculate flow-weighted annual averages was not finalized because the flow determinations do not necessarily align with the composition measurements. Finally, there is no need for the proposed requirement to calculate an annual average if only one sample is analyzed during the year. Instead, the final amendments require calculation of an annual average per constituent if more than one sample is analyzed during a year. These changes will lower costs of the final amendments relative to the proposal. Commenters did not provide data to support their contention that the composition of flared streams is relatively stable, and other data to support or refute this position are also unavailable. However, we reduced the minimum required sampling and analysis frequency for this option from quarterly to annually for the final amendments to be consistent with the current frequency specified in 40 CFR 98.233(u)(2)(ii) for onshore natural gas processing plants to determine composition of feed natural gas for calculating vented emissions from sources upstream of the demethanizer or dew point control if they do not determine composition of feed natural gas using a continuous gas composition analyzer. We believe this will provide acceptably accurate data to use in calculating emissions.</P>
                    <P>
                        The final amendments also include several options for determining composition of individual emission streams routed to a flare. One option, specified in 40 CFR 98.233(n)(4)(iii)(A) of the final amendments, is to use a continuous gas composition analyzer. This option is finalized with several changes since proposal. The proposed option (40 CFR 98.233(n)(3)(iii) as proposed) would have required sampling of purge gas, sweep gas, and auxiliary fuel at least annually. This proposed requirement was not finalized as part of the final continuous gas composition analyzer option because sampling requirements are specified as a separate option for individual streams as discussed below. We also did not finalize the proposed requirement to determine flow-weighted annual average concentrations because flow determinations are not necessarily obtained on the same time intervals as the composition measurements. Consistent with the requirements for continuous gas composition analyzers used on the total inlet stream to a flare, 
                        <PRTPAGE P="42149"/>
                        the measured mole fractions must be used to calculate annual average concentrations for each constituent to use in calculating flared emissions if a continuous gas composition analyzer is used.
                    </P>
                    <P>
                        A new option in the final amendments for determining composition of individual streams from dehydrators, hydrocarbon liquid and produced water storage tanks, and acid gas removal units is to use process simulation software in the same manner that is specified for determining composition of vented streams from these sources. These options are specified in 40 CFR 98.233(n)(4)(iii)(B)(
                        <E T="03">1</E>
                        ) through (
                        <E T="03">3</E>
                        ) of the final amendments. These options are included in the final amendments so that a facility may use the same procedures for determining composition of streams routed to flares that are also specified for determining composition of vented streams from the same source types. Another new option in 40 CFR 98.233(n)(4)(iii)(B)(
                        <E T="03">4</E>
                        ) of the final rule specifies requirements for determining composition of streams routed to flares from various emission sources at onshore production facilities, consistent with 40 CFR 98.233(n)(2)(ii) of the current rule. Finally, a new option in 40 CFR 98.233(n)(4)(iii)(B)(
                        <E T="03">6</E>
                        ) of the final rule specifies procedures for determining composition of hydrocarbon product streams, consistent with 40 CFR 98.233(n)(2)(iii) of the current rule.
                    </P>
                    <P>
                        The fourth proposed option was to analyze quarterly samples of individual streams from emission source types and to analyze annual samples of sweep gas, purge gas, and auxiliary fuel (40 CFR 98.233(n)(3)(iv) as proposed). Based on consideration of comments, this proposed option has not been finalized as proposed, but the concept of conducting individual stream sampling is incorporated into the more expansive new options in 40 CFR 98.233(n)(4)(iii)(B)(
                        <E T="03">1</E>
                        ) through (
                        <E T="03">3</E>
                        ) of the final amendments for determining composition of streams routed to flares from dehydrators, hydrocarbon liquid and produced water storage tanks, and acid gas removal units. These options specify that composition may be determined using procedures in 40 CFR 98.233(u)(2) for the applicable industry segment, with two exceptions. The first exception is that when use of a continuous gas analyzer is specified in 40 CFR 98.233(u)(2), it means the continuous gas analyzer requirements specified in 40 CFR 98.233(n)(4)(iii)(A) of the final amendments. This change will ensure consistent application of continuous gas composition analyzer requirements to all sources in all industry segments. The second exception is that when 40 CFR 98.233(u)(2)(i) specifies using “your most recent available analysis” to determine composition, the final amendments require using annual samples. The current rule also requires onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities to determine composition using the procedures in 40 CFR 98.233(u)(2)(i). However, requiring annual sampling in the final amendments instead of the current requirement to use the most recent available analysis will help ensure the use of representative samples, and the requirement for sampling annually was specified to be consistent with the annual sampling frequency for other streams as discussed previously. Similarly, for streams from any source type other than those identified in 40 CFR 98.233(n)(4)(iii)(B)(1) through (4), including sweep, purge, and auxiliary fuel, 40 CFR 98.233(n)(4)(iii)(B)(5) in the final amendments also specify that composition may be determined using the applicable procedures in 40 CFR 98.233(u)(2). Finally, since the procedures in 40 CFR 98.233(u)(2) require determination of only the GHG composition, 40 CFR 98.233(n)(4)(iii)(B)(
                        <E T="03">7</E>
                        ) in the final amendments requires determination of representative compositions of ethane, propane, butane, and pentanes plus based on process knowledge and best available data, consistent with requirements in 40 CFR 98.233(n)(2)(iii) of the current rule.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter indicated that operators should have the opportunity to measure flare gas HHV directly using, for example, continuous gas analyzers or by using a sound speed methodology from an ultrasonic flowmeter. The commenter noted that this latter method can provide reliable real-time measurement, is highly accurate, can be implemented with minimum cost, and is easy to maintain. The commenter cited a specific patent “Online Analyzers for Flare Gas Processing”, which describes a system that has been used successfully in the field.
                        <SU>64</SU>
                        <FTREF/>
                    </P>
                    <FTNT>
                        <P>
                            <SU>64</SU>
                             US Patent Pub. No.: US 2022/0107289 A1. April 7, 2022. Available at: 
                            <E T="03">https://patentimages.storage.googleapis.com/6b/46/97/d1524f32c62da7/US20220107289A1.pdf.</E>
                        </P>
                    </FTNT>
                    <P>
                        <E T="03">Response:</E>
                         The EPA agrees with the commenter that direct measurement of the HHV should be allowed in addition to the calculation of HHV from concentration data and the final provisions have been changed from proposal accordingly. In 40 CFR 98.233(n)(8), the final rule specifies that the annual average HHV may be directly measured using a calorimeter or by using a continuous gas composition analyzer that automatically calculates the HHV based on the measured composition. In addition to direct measurement methods, the final rule also specifies that annual average HHV may be calculated based on the annual average compositions determined using continuous gas composition analyzers, periodic sampling and analysis, or process simulation or engineering calculations. As discussed in a previous response in this section, the periodic sampling and analysis for gas composition must be at least annually in the final rule as opposed to at least quarterly in the proposed rule. Another previous response in this section provides information regarding the addition of process simulation and engineering calculation options for determining composition in the final rule.
                    </P>
                    <P>The final rule, however, does not cite the specific methodology described by the commenter. With regard to the patent mentioned, the EPA agrees that it appears to be an efficient method to continuously measure the net heating value of a gas stream. However, no information was provided regarding how this would be converted to HHV as required by the rule.</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter recommended that the EPA should also require reporters that elect to be in Tier 1 or Tier 2 to keep and maintain records consistent with the recordkeeping requirements under the respective NESHAP CC, NSPS OOOOb, and approved state plan requirements. For Tier 1, the commenter recommended including the recordkeeping requirements under 40 CFR 63.655(i)(9); for Tier 2 the commenter recommended including the recordkeeping requirements consistent with 40 CFR 60.5420b(c)(3)(ii)(A) through (H). According to the commenter, maintaining such records will allow EPA staff to verify additional compliance with the respective flare requirements to ensure more accurate emissions reporting.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA agrees with the commenter that additional recordkeeping is needed to ensure that facilities that are not subject to the NESHAP CC or NSPS OOOOb but elect to comply with the Tier 1 or Tier 2 efficiencies are achieving the applicable efficiencies for purposes of the subpart W calculation methodology. Thus, the EPA has strengthened recordkeeping 
                        <PRTPAGE P="42150"/>
                        requirements in the final rule for facilities complying with the Tier 1 or Tier 2 efficiencies to align with the recordkeeping requirements for flares in NESHAP CC and NSPS OOOOb, respectively. Specifically, for Tier 1, 40 CFR 98.233(n)(1)(i) requires compliance with the recordkeeping requirements in 40 CFR 63.655(i)(2) and (3) for enclosed combustion devices and 40 CFR 63.655(i)(9) for open flares. For Tier 2, 40 CFR 98.233(n)(1)(ii)(A), (B), and (C) require compliance with the recordkeeping requirements in 40 CFR 60.5420b(c)(11).
                    </P>
                    <P>
                        For Tier 2, the commenter cited the recordkeeping requirements in 40 CFR 60.5420b(c)(3)(ii)(A) through (H) of the December 6, 2022, Supplemental Proposal. These sections have been rearranged in the final NSPS OOOOb making it difficult to determine exactly which recordkeeping requirements in the final NSPS OOOOb the commenter would recommend including in subpart W. However, some of the provisions in the sections cited by the commenter involved records of certifications (
                        <E T="03">e.g.,</E>
                         for closed vent systems or to document why it is infeasible to comply with associated gas recovery requirements), records of periods of temporary venting of associated gas, records of bypass monitoring, and closed vent system inspection records that we have not included in the final subpart W. Requirements to certify both closed vent system inspections and reasons for why it is infeasible to comply with associated gas recovery requirements and related recordkeeping requirements are not included in this rulemaking because subpart W is an emissions reporting rule, not an emissions control rule. Records related to associated gas venting are not addressed in 40 CFR 98.233(n) because the methodology for calculating vented associated gas emissions, including temporary venting of streams that are normally flared, is specified in 40 CFR 98.233(m) of the final rule. The final rule does not require facilities that elect to comply with the Tier 2 efficiencies to implement NSPS OOOOb bypass device and closed vent system requirements, including related recordkeeping requirements. These requirements are included in NSPS OOOOb to ensure that the emission standards for emission source types are met, but these provisions are not needed to ensure the efficiency of the flare is met for the portion of the flow from a source that is routed through the flare. However, if there are leaks from a closed vent system or a bypass device diverts flow from entering a flare, then those volumes cannot be assumed to be controlled by the flare. Therefore, for a facility that measures or calculates flow volumes routed to flares from individual sources (instead of measuring the total flow at the flare inlet), 40 CFR 98.233(n)(3)(ii) in the final rule specifies that the closed vent system leaks and bypass volumes must be calculated based on engineering calculations, process knowledge, and best available data and subtracted from the measured or calculated flow volumes from the applicable sources to determine the flow routed to the flare. The final rule also specifies that the estimated closed vent system leaks and bypass volumes must be used in the calculation and reporting of vented emissions from the applicable sources. These requirements will ensure that the closed vent system leaks and bypass emissions are properly estimated, consistent with the directive under CAA section 136(h) to ensure that reporting under subpart W accurately reflects total methane emissions. We have also included a harmonizing reporting requirement in 40 CFR 98.236(n)(11) of the final rule for reporters to indicate whether the reported volumes for each stream from an individual source has been adjusted to account for closed vent system leaks or bypass volumes. In the EPA's verification process, this information is expected to help identify facilities that should report vented emissions from sources that also report flared emissions. Finally, the recordkeeping requirements specific to flare design and operation in 40 CFR 60.5420b(c)(11) are cross-referenced from 40 CFR 60.5420b(c)(3). Thus, since these are the only NSPS OOOOb recordkeeping requirements that are included in the final rule, we have directly cross-referenced the recordkeeping requirements in 40 CFR 60.5420b(c)(11) from 40 CFR 98.236(n)(3)(ii) of the final rule.
                    </P>
                    <HD SOURCE="HD3">2. Reporting Requirements for Flared Emissions</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>The EPA is finalizing several changes to the reporting requirements for flares. These changes are to align reporting in 40 CFR 98.236(n) with the final revisions to the calculation methods specified in 40 CFR 98.233(n), consistent with section II.B. of this preamble, and to improve the verification process, obtain a better understanding of the design and operation of flares in each of the industry segment to help future policy determinations, and clarify ambiguous provisions.</P>
                    <P>
                        First, the EPA is finalizing as proposed the replacement of the source-specific flared CH
                        <E T="52">4</E>
                        , CO
                        <E T="52">2</E>
                        , and N
                        <E T="52">2</E>
                        O emissions reporting requirements currently in 40 CFR 98.236(e), (g), (h), (j), (k), (l), (m), and (n) with a requirement to disaggregate total reported CH
                        <E T="52">4</E>
                        , CO
                        <E T="52">2</E>
                        , and N
                        <E T="52">2</E>
                        O emissions per flare to the source types that routed gas to the flare as described in section III.N.1. of this preamble. The total emissions per flare must be disaggregated to the source types specified in 40 CFR 98.236(n)(19). The source types listed in 40 CFR 98.236(n)(19) include all of the source types for which flared emissions currently must be reported, except that flared emissions from condensate storage tanks must be included in the collective emissions from “other” flared sources rather than being disaggregated separately. Additionally, the final amendments, as proposed, require disaggregation of flared emissions that are attributable to AGR vents (flared emissions from NRU vents must be included in the category of “other” flared sources). In addition to aligning the reporting with the final calculation methodology, reporting the disaggregated emissions per flare rather than per facility, sub-basin, or county (as currently required), and rather than per well-pad site, gathering and boosting site, or facility (as is required in the final amendments for vented emissions), will provide the EPA and other stakeholders with a better understanding of the impact of different emission source types on the performance of flares.
                    </P>
                    <P>
                        Second, we are finalizing as proposed adjustments to several of the existing reporting elements to align with proposed changes to the calculation methodology. For example, existing 40 CFR 98.236(n)(4) requires reporting of the total volume of gas routed to the flare. As described in section III.N.1. of this preamble, the final amendments add an option for reporters to determine volume of each stream routed to the flare. To align with this monitoring approach, 40 CFR 98.236(n)(11) in the final amendments adds a requirement to report the volumes for each of the individual streams if the reporter elects to determine the flow rate of the individual streams rather than the total. Similarly, existing 40 CFR 98.236(n)(7) and (8) require reporting of the CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                         in the feed gas to the flare. To align with the final option that allows determination of gas composition at all of the source stream levels as an alternative to determination of the composition at the flare inlet, as 
                        <PRTPAGE P="42151"/>
                        discussed in section III.N.1. of this preamble, 40 CFR 98.236(n)(14) and (15) in the final amendments require reporting of the annual CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                         mole fractions for each of the individual streams routed to the flare if the reporter elects to determine composition of those streams.
                    </P>
                    <P>Further, the final 40 CFR 98.236(n)(7) requires reporters to indicate whether flow to the flare is measured at the inlet to the flare or determined for individual streams routed to the flare, and if it is measured at the inlet to the flare, then the reporter must indicate whether the volume was determined using a continuous flow measurement device or if it was determined using monitored parameters and engineering calculations. If the flow is determined for individual streams routed to the flare, the reporter must indicate, for each stream, whether the volume was determined using a continuous flow measurement device, using monitored parameters and engineering calculations, or other simulation or engineering calculation methods. Similarly, the final 40 CFR 98.236(n)(8) requires reporters to indicate whether gas composition was determined at the inlet to the flare using a continuous gas analyzer, sampling and analysis, or if composition was determined for the individual streams that are routed to the flare. If the composition is determined for individual streams routed to the flare, the reporter must indicate, for each stream, whether the composition was determined using a continuous gas analyzer, sampling and analysis, or other simulation or engineering calculation methods. The final requirements in these sections have been revised from proposal to align with the final revisions to the calculation methodology.</P>
                    <P>
                        Third, we are finalizing requirements in 40 CFR 98.236(n)(12) (proposed 40 CFR 98.236(n)(13)) for destruction and combustion efficiencies. Proposed 40 CFR 98.236(n)(13) would require reporting of the combustion efficiency used to calculate emissions from each flare. As discussed in section III.N.1. of this preamble, the final amendments were revised from proposal to require use of both destruction efficiencies and combustion efficiencies to calculate flared emissions. Additionally, as discussed in section III.N.1. of this preamble, the final amendments include an option to use efficiencies higher than the defaults if the reporter implements an alternative test method that is approved as specified in NSPS OOOOb. To align with these revisions to the calculation methodology, 40 CFR 98.236(n)(13) in the final amendments requires reporting of the destruction efficiency used for each flare. Additionally, 40 CFR 98.236(n)(13) in the final amendments requires reporting, as proposed, of a flow-weighted destruction efficiency if the reporter calculates emissions for part of the year using one destruction efficiency and calculates emissions for the rest of the year using a different destruction efficiency. In a change from the proposal, the final amendments require reporting of flow-weighted average combustion efficiency fractions to three decimal places instead of one decimal place; the proposed requirement was incorrect because the efficiencies are to be reported as fractions (
                        <E T="03">i.e.,</E>
                         consistent with the values used in equations W-19 and W-20), not percentages. These data will help with verification of the reported emissions.
                    </P>
                    <P>
                        We are finalizing the addition of several new reporting elements in 40 CFR 98.236(n)(13) to align with changes to the final flare efficiency options. If you comply with Tier 1 or Tier 2, new requirements to report the number of days in periods of 15 or more consecutive days when you did not conform with all cited provisions in 40 CFR 98.233(n)(1)(i) or (ii) are included in both final 40 CFR 98.236(n)(13)(i) for Tier 1 and in 40 CFR 98.236(n)(13)(ii) for Tier 2. These reporting requirements align with the requirements in the final Tier 1 and Tier 2 calculation methodologies to use the Tier 3 efficiencies for periods of monitoring parameter non-conformance that exceed 15 consecutive days. For facilities that report flares using a destruction efficiency of 95 percent (Tier 2), final 40 CFR 98.236(n)(13)(ii), as proposed, requires reporters to indicate whether the flare is subject to NSPS OOOOb or whether the reporter is electing to implement flare procedures that are specified in NSPS OOOOb. The final amendments also extend this reporting requirement to whether the reporter is subject to a state or Federal plan in 40 CFR part 62 implementing EG OOOOc or is electing to follow a state or Federal Plan in 40 CFR part 62 implementing EG OOOOc. Another new data element in final 40 CFR 98.236(n)(13) requires facilities with flares that are enclosed ground level flares or enclosed elevated flares that are not required to comply with NSPS OOOOb or state or Federal Plan in 40 CFR part 62 implementing EG OOOOc but are electing to comply with Tier 2 efficiencies to indicate if the most recent performance test was conducted using the method in 40 CFR 60.5413b(b) (
                        <E T="03">i.e.,</E>
                         onsite testing), the method in 40 CFR 60.5413b(d) (
                        <E T="03">i.e.,</E>
                         manufacturer testing), or the alternative method specified in 40 CFR 98.233(n)(1)(iv) (
                        <E T="03">i.e.,</E>
                         OTM-52). Finally, new reporting elements are added in final 40 CFR 98.236(n)(13)(iii) that require reporters to indicate if they are using an efficiency for an alternative test method approved under 40 CFR 60.5412b(d) and if they are, to also report the approved destruction efficiency and the date when the reporter started to use the alternative test method. This information will help the EPA verify the reported data.
                    </P>
                    <P>
                        Fourth, existing 40 CFR 98.236(n)(12) requires reporting of whether a CEMS was used to measure CO
                        <E T="52">2</E>
                         emissions from the flare. This reporting requirement is retained in 40 CFR 98.236(n)(20) as proposed, along with a requirement that the CO
                        <E T="52">2</E>
                         mole fraction of the gas sent to the flare should not be reported when using CEMS because equation W-20 is not used to calculate CO
                        <E T="52">2</E>
                         emissions when using a CEMS.
                    </P>
                    <P>
                        Fifth, one objective of the current flare reporting requirements is to obtain information on the total number of flares and their operating characteristics. We are finalizing as proposed the addition of a few new flare-specific reporting elements to help us better understand the state of flaring in the industry for carrying out provisions under the CAA and to improve data quality, such as an indication of the type of the flare (
                        <E T="03">e.g.,</E>
                         open ground-level flare, enclosed ground-level flare, open elevated flare, or enclosed elevated flare) in 40 CFR 98.236(n)(4) and the type of flare assist (
                        <E T="03">e.g.,</E>
                         unassisted, air-assisted (with indication of single-, dual-, or variable-speed fan), steam-assisted, or pressure-assisted) in 40 CFR 98.236(n)(5). These data will help the EPA assess the impact of design and operation on emissions and may be useful in analyses for potential future policy decisions related to flares under the CAA. To harmonize the final reporting requirements with the final requirement to either continuously monitor or periodically inspect for the presence of a pilot flame as discussed in section III.N.1. of this preamble, we are finalizing as proposed 40 CFR 98.236(n)(6) requiring that reporters indicate for each flare whether they continuously monitor for the presence of a pilot flame, conduct periodic visual inspections, or both. As proposed, if periodic visual inspections are conducted, 40 CFR 98.236(n)(6) also requires reporting of the count of inspections conducted during the year. Since the final rule requires a continuous pilot, we are not finalizing the proposed requirement to report whether the inspected flare has a 
                        <PRTPAGE P="42152"/>
                        continuous pilot or auto igniter. For a pilot flame that is monitored continuously, the final amendments as proposed also require reporting of the number of times the continuous monitoring devices were out of service or otherwise inoperable for a period of more than one week.
                    </P>
                    <P>The EPA is not finalizing the proposed requirement for facilities in the Onshore Petroleum and Natural Gas Production industry segment, the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment, and the Onshore Natural Gas Processing industry segment to report an estimate of the fraction of the gas burned in the flare that is obtained from other facilities specifically for flaring as opposed to being generated in on-site operations. At proposal, we indicated that this proposed data element would provide information on what source types are generating significant emissions from miscellaneous flared sources. However, after consideration of public comments indicating that the fraction would be difficult to determine, we have decided not to take final action on this requirement at this time.</P>
                    <P>
                        Finally, because the proposed calculation methodologies for flares would have required measurement of flow and composition rather than use of source-specific calculation methodologies, the EPA also proposed that source types that are flared for the entire year would not be required to report the activity data associated with those source-specific calculation methodologies. Instead, those sources would have only been required to report identifying information about the unit and indicate that emissions were routed to a flare the entire year under the individual source type, and all other activity data related to the flares would have been reported under 40 CFR 98.236(n). Under the final amendments, if the flow of the gas routed to a flare is not measured according to 40 CFR 98.233(n)(3)(i) and (n)(3)(ii)(A) and/or the composition of the gas routed to a flare is not measured according to 40 CFR 98.233(n)(4)(i) and (ii), then the reporter must determine the flow and composition of the gas using the calculation methods for that source type, per final 40 CFR 98.233(n)(3)(ii)(B) and 98.233(n)(4)(iii). Because the final amendments provide multiple methods for calculating the flow and composition of gas streams routed to flares, the EPA is not finalizing the consolidation of all the flare-related activity data under 40 CFR 98.236(n), as was proposed. Instead, for the disaggregated sources listed in 40 CFR 98.233(n)(3)(ii)(B)(
                        <E T="03">1</E>
                        ) through (7), the EPA is finalizing reporting requirements within the section for each source type that is routed to a flare. These source-specific reporting requirements apply in addition to the information required to be reported under 40 CFR 98.236(n) for the flare. Specifically, for these source types with gas routed to a flare, reporters will continue to report the required identifying information (
                        <E T="03">e.g.,</E>
                         unit ID, well ID, well-pad ID) and then indicate at the specified reporting level (
                        <E T="03">e.g.,</E>
                         by well or individual source type, by well-pad site or gathering and boosting site) whether the gas was routed to the flare for part of the year or the entire year and provide the flare stack identifier or name as well as the unique ID for the stream routed to the flare.
                    </P>
                    <P>
                        Reporters will also report whether the gas flow and composition were determined through measurement or the source-specific methodologies for sources listed in 40 CFR 98.233(n)(3)(ii)(B)(
                        <E T="03">1</E>
                        ) through (
                        <E T="03">7</E>
                        ). In cases where the reporter is using source type-specific calculation methods, it is essential that certain activity data be reported for the source type for accurate verification of reported emissions data and also accurate allocation of disaggregated emissions data, if applicable. Therefore, if a source-specific methodology is used, reporters will be required to report the same activity data for the source type as they would if the gas were vented directly to the atmosphere. For example, if an acid gas removal vent is routed to a flare and the flow and composition of the gas routed to the flare is determined using Calculation Method 4, the reporter will be required to provide the activity data associated with Calculation Method 4 under 40 CFR 98.236(d)(2)(iv). Other examples include completions and workovers with hydraulic fracturing, for which the reporter will be required to indicate the calculation method used and data specific to equation W-10A and W-10B; completions and workovers without hydraulic fracturing, for which the reporter will be required to provide the inputs to equations W-13A and W-13B; and associated gas flaring, for which the reporter will be required to provide the inputs to equation W-18. These data are essential for the verification of flared emissions and the identification of the flare to which the emission sources are routed.
                    </P>
                    <P>
                        For sources that are routed to flares other than those listed in 40 CFR 98.233(n)(3)(ii)(B)(
                        <E T="03">1</E>
                        ) through (
                        <E T="03">7</E>
                        ), flow to the flares is required to be determined using engineering calculations based on process knowledge, company records, and best available data in accordance with 40 CFR 98.233(n)(3)(ii)(B)(
                        <E T="03">8</E>
                        ), and no additional reporting requirements within the section for each source type are being finalized.
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to the reporting requirements for flare stacks.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters opposed the proposal of the requirement in proposed 40 CFR 98.236(n)(10) to report the estimated fraction of total volume flared that was received from another facility solely for flaring. Commenters indicated that this information would be difficult to determine and would not provide meaningful information. The commenters stated that the EPA should require reporting of the emissions from a flare stack without considering whether the gas was received from another facility.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         After review of these comments, we are not taking final action at this time on the proposed reporting requirement. In the preamble to the proposed rule, we indicated that this proposed data element would help the EPA understand what source types are generating the large amounts of flared gas reported under miscellaneous flared sources, and that if the source type also is not currently subject to source-specific reporting of vented emissions, then a potentially large quantity of vented emissions might go unreported. However, the proposed data element would have only indicated whether the gas was received from a different facility to be flared; it would not have told us what emission source generated the gas. In addition, in this final rule, we are finalizing the addition of numerous new emission sources under subpart W, so the likelihood that another potentially large quantity of vented emissions might go unreported has decreased. The EPA not taking final action on this reporting requirement at this time does not affect the general requirements to calculate and report total emissions from each flare stack.
                    </P>
                    <HD SOURCE="HD3">3. Definition of Flare Stack Emissions</HD>
                    <P>
                        The term “flare stack emissions” in 40 CFR 98.238 is currently defined to mean “CO
                        <E T="52">2</E>
                         and N
                        <E T="52">2</E>
                        O from partial combustion of hydrocarbon gas sent to a flare plus CH
                        <E T="52">4</E>
                         emissions resulting from the incomplete combustion of hydrocarbon gas in flares.” As noted in the 2023 Subpart W Proposal, the current definition does not clearly convey the EPA's intent that the CO
                        <E T="52">2</E>
                         that enters a flare should be reported as flare stack emissions and it implies N
                        <E T="52">2</E>
                        O emissions 
                        <PRTPAGE P="42153"/>
                        only result from partial combustion of hydrocarbons in the gas routed to the flare, which is not the case. Consistent with section II.D. of this preamble, in order to eliminate the unintended inconsistency between the definition and the intent that CO
                        <E T="52">2</E>
                         in gas routed to the flare is to be reported as emissions from the flare, to clarify the requirement to calculate and report total CO
                        <E T="52">2</E>
                         that leaves the flare, and to clarify the source of flared N
                        <E T="52">2</E>
                        O emissions, we are finalizing as proposed the revision of the definition of the term “flare stack emissions” in 40 CFR 98.238 to mean CO
                        <E T="52">2</E>
                         in gas routed to a flare, CO
                        <E T="52">2</E>
                         from partial combustion of hydrocarbons in gas routed to a flare, CH
                        <E T="52">4</E>
                         resulting from the incomplete combustion of hydrocarbons in gas routed to a flare, and N
                        <E T="52">2</E>
                        O resulting from operation of a flare. The EPA received only supportive comments regarding the revisions to the definition of “flare stack emissions.” See the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
                    </P>
                    <HD SOURCE="HD2">O. Compressors</HD>
                    <P>
                        Compressors are used across the petroleum and natural gas industry to raise the pressure of and convey natural gas or CO
                        <E T="52">2</E>
                        . The two main types of compressors used in the industry are centrifugal compressors and reciprocating compressors. We are finalizing several amendments to subpart W related to compressors as proposed, finalizing some amendments with revisions from proposal, and not finalizing other proposed amendments.
                    </P>
                    <HD SOURCE="HD3">1. Mode-Source Combination Measurement Requirements</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>The EPA is finalizing several amendments related to the “as found” measurement requirements to improve the quality of data collected for compressors. First, standby-pressurized-mode was not included as a mode for centrifugal compressors in the existing subpart W definition of “compressor mode” and no compressor mode-source combinations were defined for centrifugal compressors in standby-pressurized-mode. While centrifugal compressors are seldom in the standby-pressurized-mode, there have been several occasions when reporters have indicated through the GHGRP Help Desk that a centrifugal compressor was in this mode during the “as found” measurement. Therefore, we are finalizing as proposed the revised definition of compressor mode in 40 CFR 98.238 that includes standby-pressurized-mode as a defined mode for centrifugal compressors. We are also finalizing as proposed the requirement to measure volumetric emissions from the wet seal oil degassing vent or dry seal vent, as applicable (see discussion in the following paragraph) and the volumetric emissions from blowdown valve leakage through the blowdown vent when the compressor is found in standby-pressurized-mode (40 CFR 98.233(o)(1)(i)(C)), consistent with section II.A. of this preamble.</P>
                    <P>Second, dry seals on centrifugal compressors were not included in the existing subpart W definition of “compressor source” and no compressor mode-source combinations were defined for dry seals on centrifugal compressors. While emissions from wet seal oil degassing vents are expected to be larger than from dry seals when the dry seal compressor is well-maintained and operating normally, dry seals still contribute to centrifugal compressor emissions, especially if they are poorly maintained or there are unforeseen upset conditions. Therefore, to better characterize the emissions from dry seal centrifugal compressors, we are finalizing the revised definition of compressor source in 40 CFR 98.238 to include dry seal vents as one of the defined compressor sources for centrifugal compressors. We are also finalizing as proposed the requirement to measure volumetric emissions from the dry seal vents in both operating-mode and in standby-pressurized-mode (40 CFR 98.233(o)(2)(iii)), consistent with section II.B. of this preamble. Under the final provisions, the measurement methods for the dry seal vents are similar to those provided for reciprocating compressor rod packing emissions and include the use of temporary or permanent flow meters, calibrated bags, and high volume samplers. We are finalizing as proposed that screening methods may also be used to determine if a quantitative measurement is required. We are finalizing as proposed the specification that acoustical screening or measurement methods are not applicable to screening dry seal vents because emissions from dry seal vents are not a result of through-valve leakage. As proposed, certain requirements in 40 CFR 98.236(o) are now applicable to the dry seal compressor source under the final rule, including new reporting requirements in 40 CFR 98.236(o)(1)(x) to report the number of dry seals on centrifugal compressors and in 40 CFR 98.236(o)(2)(B) to report dry seals as one of the centrifugal compressor sources.</P>
                    <P>
                        Third, we are finalizing as proposed the revision to 40 CFR 98.233(p)(1)(i) to require measurement of rod packing emissions for reciprocating compressors when found in the standby-pressurized-mode because recent studies indicate that rod packing emissions can occur while the compressor is in this mode.
                        <SU>65</SU>
                        <FTREF/>
                         The inclusion of this compressor mode-source combination more accurately reflects compressor emissions, consistent with section II.A. of this preamble.
                    </P>
                    <FTNT>
                        <P>
                            <SU>65</SU>
                             Subramanian, R. 
                            <E T="03">et al</E>
                            . “Methane Emissions from Natural Gas Compressor Stations in the Transmission and Storage Sector: Measurements and Comparisons with the EPA Greenhouse Gas Reporting Program Protocol.” 
                            <E T="03">Environ. Sci. Technol.</E>
                             49, 3252-3261. 2015. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>Fourth, we are finalizing as proposed the elimination of the requirement in 40 CFR 98.233(o) to conduct a measurement in not-operating-depressurized-mode at least once every three years, consistent with section II.C. of this preamble. We originally included the requirement for compressors that were not measured in not-operating-depressurized-mode during the “as found” measurements for three consecutive years in order to obtain a sufficient amount of data for this mode (75 FR 74458, November 30, 2010). However, based on data collected under subpart W thus far, many compressors are in not-operating-depressurized-mode for 30 percent of the time or more. Therefore, facilities are able to obtain a sufficient number of measurements in not-operating-depressurized-mode to calculate an accurate mode-source specific emission factor without the additional requirement. As such, the extra measurements are no longer necessary, and the final amendments in this rule make the annual measurements true “as found” measurements. We are also finalizing as proposed the removal of the reporting requirement in 40 CFR 98.236(o) to indicate if the compressor had a scheduled depressurized shutdown during the reporting year because that information is only collected to verify compliance with the requirement to conduct a measurement in not-operating-depressurized-mode at least once every three years.</P>
                    <P>
                        Fifth, we are finalizing one additional change to the proposed 40 CFR 98.233(o)(2)(iii) to clarify the specific location where the dry seal measurement should be conducted. Language has been added to note that 
                        <PRTPAGE P="42154"/>
                        the measurement should be made on the compressor side dry seal. This change was made to prevent measurements on the outboard side dry seal, because process gas emissions from the dry seal on the outboard side are very low.
                        <SU>66</SU>
                        <FTREF/>
                    </P>
                    <FTNT>
                        <P>
                            <SU>66</SU>
                             Reducing Emissions from Compressor Seals; Lessons Learned from Natural Gas STAR. Available at 
                            <E T="03">https://www.epa.gov/sites/default/files/2017-09/documents/reducingemissionsfromcompressorseals.pdf</E>
                            . Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to mode-source combination measurement requirements.</P>
                    <P>
                        <E T="03">Comment:</E>
                         All commenters supported the proposed changes to the mode-source combination measurement requirements. In addition, one commenter suggested a change to 40 CFR 98.233(o)(2)(iii) to clarify that the dry seal measurement should be conducted on the compressor side.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We agree with the commenter that clarity is needed to describe where the dry seal measurement should be conducted. Thus, in the final rule, we are adding appropriate language to 40 CFR 98.233(o)(2)(iii) to clarify that dry seal measurements should be conducted on the compressor side dry seal. All other changes to mode-source combination measurement requirements are being finalized as proposed.
                    </P>
                    <HD SOURCE="HD3">2. Measurement Methods</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>The EPA is finalizing several amendments related to the measurement method requirements to improve the quality of data collected for compressors. First, we are finalizing as proposed the revisions to the allowable methods for measuring wet seal oil degassing vents. Previously, the only method provided in 40 CFR 98.233(o)(2)(ii) for measuring volumetric flow from wet seal oil degassing vents was the use of a temporary or permanent flow meter. We are finalizing the revision to 40 CFR 98.233(o)(2)(ii) allowing the use of calibrated bags and high volume samplers. As proposed, under the final provisions we specify that the use of screening methods for wet seal oil degassing vent measurement is not allowed, because wet seal oil degassing vents are expected to always have some natural gas flow. These revisions to 40 CFR 98.233(o)(2)(ii) provide improved clarity of the wet seal oil degassing provisions and allow an additional measurement method that was determined to be accurate for this source, consistent with section II.B. of this preamble.</P>
                    <P>
                        Second, we are finalizing, with two revisions from proposal, the removal of acoustic leak detection from the screening and measurement methods allowed for manifolded groups of compressor sources. Acoustic leak detection is applicable only for through-valve leakage. Therefore, the acoustic method for screening or measurement can be applied only to individual compressor sources associated with through-valve leakage (
                        <E T="03">i.e.,</E>
                         blowdown valve leakage or isolation valve leakage), but it cannot be used for screening emissions from or measurement of emissions from a vent that contains a group of manifolded compressor sources downstream from the individual valves or other sources that may be manifolded together. The previous inadvertent inclusion of this method for manifolded compressor sources was in error and we are finalizing its removal from 40 CFR 98.233(o)(4)(ii)(D) and (E) and 40 CFR 98.233(p)(4)(ii)(D) and (E) to improve accuracy of the measurements, consistent with section II.B. of this preamble.
                    </P>
                    <P>The final provisions include minor changes from the proposal to add two new paragraphs at 40 CFR 98.233(o)(4)(ii)(F) and 40 CFR 98.233(p)(4)(ii)(F) to allow the use of acoustic leak detection as a tool for manifolded compressor sources only after screening (to determine that there is a leak) but prior to measurement (to quantify the leak). This revision does not negate the fact that acoustic leak detection should only be used on through-valve leakage for screening and measurement. This revision simply allows the use of acoustic leak detection, according to 40 CFR 98.234(a)(5), as a tool to identify one leaking compressor valve among a group of multiple potentially leaking compressor valves. A screening method from 40 CFR 98.234(a)(1) through (3) will still be required to identify that a leak is occurring in the manifolded group of compressors, and a measurement method from 40 CFR 98.233(o)(4)(ii)(A) through (D) or 40 CFR 98.233(p)(4)(ii)(A) through (D) will still be required to quantify the leak, once the leaking compressor valve is identified. Acoustic leak detection will only be allowed to determine which compressor included in the manifolded group is leaking, in order to make proper measurement of the leak easier to perform. We included these changes after consideration of public comment.</P>
                    <P>Third, we are finalizing as proposed a number of clarifications to the references to the allowed measurement methods to correct errors and improve the clarity of the rule, consistent with section II.D. of this preamble. These final revisions include: revising 40 CFR 98.233(o)(1)(i)(A) and (B) to reference 40 CFR 98.233(o)(2)(i) instead of specific subparagraphs of that paragraph that may be construed to limit the methods allowed for blowdown or isolation valve leakage measurements; revising 40 CFR 98.233(p)(1)(i)(A), (B) and (C) to reference 40 CFR 98.233(p)(2)(i) instead of specific subparagraphs of that paragraph that may be construed to limit the methods allowed for blowdown or isolation valve leakage measurements; revising 40 CFR 98.233(p)(1)(i)(A) and (C) to reference “paragraph (p)(2)(ii) or (iii) of this section as applicable” instead of only “paragraph (p)(2)(ii)” to clarify that measurement of rod packing emissions without an open-ended vent line are to be made according to 40 CFR 98.233(p)(2)(iii); and revising 40 CFR 98.233(p)(2)(ii)(C) and (iii)(A) to clarify that acoustic leak detection is not an applicable screening method for rod packing emissions because rod packing is not through-valve leakage.</P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments related to measurement methods.</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter suggested an edit to allow acoustic leak detection in limited circumstances. The commenter asked that the EPA selectively retain the use of acoustic devices for manifolded compressors to identify the source of the leak, but not to quantify emissions. The use of acoustic leak detection would help determine which compressor valve should be measured downstream of the manifold, using one of the other methods specified in 40 CFR 98.233(o)(4)(ii)(A) through (D) or 40 CFR 98.233(p)(4)(ii)(A) through (D). Specifically, the commenter asked that if one of the screening methods specified in 40 CFR 98.234(a)(1) through (3) identifies a leak in a manifolded group of compressor sources, that the reporter be allowed to use acoustic leak detection, according to 40 CFR 98.234(a)(5), to identify which compressor valve is leaking.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA reviewed the comment and determined that a limited retainment of the use of acoustic leak detection, to identify which compressor valve in a manifolded group of 
                        <PRTPAGE P="42155"/>
                        compressor sources is leaking, is appropriate. In this case, acoustic leak detection is not being relied upon to identify whether there is a leak in the first place. Instead, this revision allows the use of acoustic leak detection as a tool to identify the source of a leak from a group of manifolded compressors. However, acoustic leak detection will not be allowed to be used as a screening or measurement method to identify or quantify emissions from a manifolded group of compressors. This revision has been included in the final provision.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter asked that the rule allow flexibility to integrate advanced technologies that become available, such as the option of using an OGI emissions quantification system, which the commenter noted as a technology still under development, as an accepted technology for methane emissions quantification when the performance of that technology is confirmed.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         Without specific details that are necessary to evaluate and incorporate such methodologies, such as the performance, accuracy or precision of the aforementioned technology, and how the aforementioned technology can be applied specifically to compressor emission sources, the EPA is not able to fully evaluate for potential incorporation in this rulemaking quantitative OGI or other technologies that are currently still under development. Therefore, at this time such technologies are not included in the final provisions.
                    </P>
                    <HD SOURCE="HD3">3. Onshore Petroleum and Natural Gas Production or Onshore Petroleum and Natural Gas Gathering and Boosting</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>As noted in the introduction to section II. of this preamble, the EPA recently finalized NSPS OOOOb and EG OOOOc for certain oil and natural gas sources. The final standards in NSPS OOOOb and the final presumptive standards in EG OOOOc include emission limits for reciprocating compressors, centrifugal compressors with wet seals, and centrifugal compressors with dry seals that apply when the compressor is in operating-mode or standby-pressurized-mode. The final standards require owners or operators to conduct volumetric emissions measurements from each reciprocating compressor rod packing or centrifugal compressor wet or dry seal on or before 8,760 hours of operation from startup or from the previous measurement. Similar to the 2016 amendments to subpart W specific to equipment leak surveys (81 FR 4987, January 29, 2016), the EPA is finalizing, with a revision from proposal, the calculation methodologies in 40 CFR 98.233(o)(10) and 40 CFR 98.233(p)(10) for compressors at onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities in subpart W so that data derived from centrifugal compressor or reciprocating compressor monitoring conducted under NSPS OOOOb or the applicable approved state plan or applicable Federal plan in 40 CFR part 62 will be required to be used to calculate emissions for subpart W reporting, consistent with section II.B. of this preamble.</P>
                    <P>For compressors at onshore petroleum and natural gas production or onshore petroleum and natural gas gathering and boosting facilities not subject to either NSPS OOOOb or an applicable approved state plan or applicable Federal plan in 40 CFR part 62, we are finalizing, with a revision from proposal, the calculation methodologies in 40 CFR 98.233(o)(10) and 40 CFR 98.233(p)(10) such that reporters have the option to calculate emissions for subpart W reporting using the same provisions for “as found” measurements as other industry segments under 40 CFR 98.233(o)(1)(i) and 40 CFR 98.233(p)(1)(i), using methods specified in 40 CFR 98.233(o)(2) through (5) or 40 CFR 98.233(p)(2) through (5), as applicable, based on the compressor mode (as defined in 40 CFR 98.238) in which the compressor was found at the time of measurement, and calculating emissions as specified in 40 CFR 98.233(o)(6) through (9) or 40 CFR 98.233(p)(6) through (9), as applicable. These revisions will allow owners and operators of onshore petroleum and natural gas production or onshore petroleum and natural gas gathering and boosting facilities to use facility measurement data in their emission calculations for compressors, consistent with section II.B. of this preamble.</P>
                    <P>The EPA is finalizing, with a revision from proposal, requirements under subpart W in 40 CFR 98.233(o)(10) and 40 CFR 98.233(p)(10) for compressors subject to the final standards in NSPS OOOOb or standards in an applicable approved state plan or applicable Federal plan codified in 40 CFR part 62, which are necessary due to the different scope and purpose of the GHGRP subpart W provisions compared to the final standards in NSPS OOOOb and the finalized presumptive standards in EG OOOOc. The EPA is finalizing as proposed that reporters conducting measurements of compressors under NSPS OOOOb or the applicable approved state plan or applicable Federal plan in 40 CFR part 62 must conduct measurements of all other compressor sources required to be measured by subpart W (based on the compressor mode (as defined in 40 CFR 98.238) in which the compressor was found at the time of measurement) specified in 40 CFR 98.233(o)(1) or 40 CFR 98.233(p)(1), using methods specified in 40 CFR 98.233(o)(2) through (5) or 40 CFR 98.233(p)(2) through (5), as applicable, and calculating emissions as specified in 40 CFR 98.233(o)(6) through (9) or 40 CFR 98.233(p)(6) through (9), as applicable.</P>
                    <P>Because the time between measurements under the final standards in NSPS OOOOb and the final presumptive standards in EG OOOOc may not result in measurements being taken every reporting year, the EPA is finalizing as proposed the requirement to use equation W-22 or equation W-27, as applicable, to calculate emissions from all mode-source combinations for any reporting year in which measurements are not required.</P>
                    <P>As discussed at proposal, the final standards in NSPS OOOOb and the finalized presumptive standards in EG OOOOc only require measurements to be taken in operating-mode or standby-pressurized-mode. If no compressor sources are measured in not-operating-depressurized-mode, reporters would not have data to develop reporter emission factors for that mode-source combination using equation W-23 and equation W-28. The EPA proposed in 40 CFR 98.233(o)(10)(i)(B) and 40 CFR 98.233(p)(10)(i)(B) that reporters with compressors subject to NSPS OOOOb or the applicable approved state plan or applicable Federal plan in 40 CFR part 62 would be required to conduct additional measurements of compressors in not-operating-depressurized-mode such that they can develop an annual reporter emission factor for isolation valve leakage in not-operating-depressurized-mode.</P>
                    <P>
                        The main revision to the proposed amendments for compressors in the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments is the removal of the aforementioned requirement to conduct measurements of compressors in not-operating-depressurized-mode on a regular basis. We received many comments suggesting the requirement was overly burdensome and difficult to implement. After consideration of public comment, the EPA is not finalizing the requirement to conduct additional measurements of compressors in not-operating-depressurized-mode. Instead, the final 
                        <PRTPAGE P="42156"/>
                        amendments only require measurements in not-operating-depressurized mode if the compressor is in not-operating-depressurized mode at the time of measurement, making the annual measurements of compressors in the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments true “as found” measurements.
                    </P>
                    <P>
                        For facilities in the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments that do not conduct measurements, we are finalizing language at 40 CFR 98.233(o)(10) and (p)(10) for compressors at Onshore Petroleum and Natural Gas Production or Onshore Petroleum and Natural Gas Gathering and Boosting facilities, consistent with section II.B. of this preamble. The compressor emission factors for these industry segments are specific to uncontrolled wet seal oil degassing vents on centrifugal compressors and uncontrolled rod packing emissions for reciprocating compressors. The language in 40 CFR 98.233(o) and (p) clearly indicates that the provisions of 40 CFR 98.233(o)(10) and (p)(10) do not apply for controlled compressor sources. Therefore, we are finalizing as proposed minor revisions to 40 CFR 98.233(o)(10) and the corresponding reporting requirements in 40 CFR 98.236(o)(5) to clarify that the compressor count used in equation W-25A should be the number of centrifugal compressors with atmospheric (
                        <E T="03">i.e.,</E>
                         uncontrolled) wet seal oil degassing vents. Similarly, we are finalizing minor revisions to 40 CFR 98.233(p)(10) and the corresponding reporting requirements in 40 CFR 98.236(p)(5) to clarify that the compressor count used in equation W-29D should be the number of reciprocating compressors with atmospheric (
                        <E T="03">i.e.,</E>
                         uncontrolled) rod packing emissions. We are also finalizing as proposed additional requirements to report the total number of centrifugal compressors at the facility and the number of centrifugal compressors that have wet seals to 40 CFR 98.236(o)(5) and additional requirements to report the total number of reciprocating compressors at the facility to 40 CFR 98.236(p)(5). These additional data provide the EPA with an improved understanding of the total number of compressors and the number of compressors that are controlled (i.e., routed to flares, combustion, or vapor recovery systems) in the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments, consistent with section II.C. of this preamble.
                    </P>
                    <P>
                        In addition, consistent with section II.B. of this preamble, and after consideration of public comment, the EPA is finalizing the proposed CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                         population emission factors in equation W-29E, while also allowing for adjustment of total operating time and mole fraction of CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                        . As discussed at proposal, the reciprocating compressor population emission factor for CH
                        <E T="52">4</E>
                         is based on the average population emission rate measured by Zimmerle 
                        <E T="03">et al.</E>
                         (2019), with a CO
                        <E T="52">2</E>
                         population emission factor derived by applying the ratio of the current CO
                        <E T="52">2</E>
                         emission factor to the current CH
                        <E T="52">4</E>
                         emission factor to the CH
                        <E T="52">4</E>
                         emission factor obtained from Zimmerle 
                        <E T="03">et al.</E>
                         (2019).
                    </P>
                    <P>
                        After consideration of public comments and review of the proposal, the EPA is finalizing a few additional changes related to reciprocating compressors. First, a new equation W-29E has been added to subpart W to calculate emissions from each reciprocating compressor at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility for which 40 CFR 98.233(p)(10)(i) does not apply and for which the facility does not elect to conduct the volumetric measurements specified in 40 CFR 98.233(p)(1), using the final emission factors and allowing for adjustment of total operating time and mole fraction of CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                        . Second, equation W-29D has been revised to calculate total emissions from all reciprocating compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility for which 40 CFR 98.233(p)(10)(i) does not apply and for which the facility does not elect to conduct the volumetric measurements specified in 40 CFR 98.233(p)(1), as a sum of all reciprocating compressor emissions calculated using equation W-29E.
                    </P>
                    <P>
                        These changes were made in response to a public comment asking to allow adjustment of total operating time and mole fraction of CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                         in the calculation of emissions from reciprocating compressors. As proposed, equation W-29D only allowed for the use of the count of total reciprocating compressors used at either an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility multiplied by the emission factor. Adjustment for total compressor operating time and specific mole fractions of CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                         is made on a compressor-specific basis. Therefore, in the final rule, equation W-29E calculates CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                         emissions from each reciprocating compressor at either an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility (allowing for adjustment to reflect actual operating time and CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                         mole fractions associated with each compressor) and equation W-29D calculates total CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                         emissions from all reciprocating compressors at either an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility using individual compressor emissions determined for each reciprocating compressor according to equation W-29E. These revisions allow for the incorporation of unit-specific data and are expected to increase the accuracy of the calculated compressor emissions, consistent with section II.B. of this preamble.
                    </P>
                    <P>
                        Additionally, corresponding changes were made for centrifugal compressors. Even though this change was not requested by commenters, the change was made for equitable treatment of both types of compressors. First, a new equation W-25B has been added to subpart W to calculate emissions from each centrifugal compressor at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility for which 40 CFR 98.233(o)(10)(i) does not apply and for which the facility does not elect to conduct the volumetric measurements specified in 40 CFR 98.233(o)(1), using the emission factors and allowing for adjustment of total operating time and mole fractions of CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                        . Second, equation W-25A has been revised (and renamed from equation W-25) to calculate total emissions from all centrifugal compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility for which 40 CFR 98.233(o)(10)(i) and (ii) do not apply, as a sum of all centrifugal compressor emissions calculated using equation W-25B.
                    </P>
                    <P>
                        Paragraphs 40 CFR 98.233(o)(10)(iii) and 98.233(p)(10)(iii) were revised and new paragraphs 40 CFR 98.233(o)(10)(iv) and 98.233(p)(10)(iv) were added to incorporate these revisions.
                        <PRTPAGE P="42157"/>
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments related to Onshore Petroleum and Natural Gas Production or Onshore Petroleum and Natural Gas Gathering and Boosting measurement methods.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Multiple commenters disagreed with the proposed amendments to 40 CFR 98.233(o)(10)(i)(B) and 40 CFR 98.233(p)(10)(i)(B) to require reporters with compressors subject to NSPS OOOOb or the applicable approved state plan or applicable Federal plan in 40 CFR part 62 to conduct additional measurements of compressors in not-operating-depressurized-mode, such that they can develop an annual reporter emission factor for isolation valve leakage in not-operating-depressurized-mode. The proposed amendments the commenters disagreed with would require reporters to measure emissions in not-operating-depressurized mode from isolation valve leakage for at least one-third of the subject compressors during any 3 consecutive calendar year period.
                    </P>
                    <P>According to one commenter, compressors used in production and gathering and boosting are rarely unpressurized while remaining at a specific location. When the compressors are no longer needed at a specific site, the commenter stated that the compressors are shut down and moved to another location. Another commenter noted that gathering and boosting facilities typically have very few compressors per site and they are generally running continuously. Not-operating-depressurized mode is an uncommon mode, so requiring a measurement in that mode is unnecessary and could lead to higher emissions, especially if a compressor is shut down to meet this requirement and there is an unexpected critical need for the compressor to be operating.</P>
                    <P>
                        <E T="03">Response:</E>
                         After consideration of public comment, the EPA is not finalizing the proposed changes to require compressor measurements in not-operating-depressurized mode such that at the end of each calendar year, reporters have taken measurements in not-operating-depressurized-mode over the last 3 consecutive calendar years for at least one-third of the compressors at the facility. Preemptively requiring a measurement in not-operating-depressurized mode, especially if compressors in the industry segments are rarely in this mode, appears to be an unnecessary requirement. The main reason to require this measurement is to ensure that reporters have a way to estimate emissions in not-operating-depressurized mode when measurements are not available (
                        <E T="03">i.e.,</E>
                         the reporter can use measurements from other years to determine an average emission factor). If compressors in these industry segments are rarely in this mode, an average emission factor is not needed. Reporters who elect to conduct the volumetric emission measurements specified in 40 CFR 98.233(o)(10)(ii) or 40 CFR 98.233(p)(10)(ii) will conduct as-found compressor measurements. Measurements in not-operating-depressurized mode will only be required if the compressor is in not-operating-depressurized mode at the time of measurements. If the dataset from these reporters shows a high instance of not-operating-depressurized mode measurements from compressors at onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities than indicated by the commenters, the EPA may reconsider this requirement in future rulemakings.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter noted that equation W-29D in 40 CFR 98.233(p) does not allow for adjustment based on gas composition. Due to the wide variety in the composition of gas produced from different basins and formations across the U.S., the commenter asked that the emission factor method allow for adjustment based on CO
                        <E T="52">2</E>
                         and CH
                        <E T="52">4</E>
                         composition reflective of each compressor. The commenter noted that composition adjustment of Emission Factor-based calculations is allowed under subpart W for pneumatic devices, pneumatic pumps, and equipment leaks.
                    </P>
                    <P>The commenter also noted that equation W-29D in 40 CFR 98.233(p) does not allow for adjustment based on the number of hours a compressor operates during a calendar year. The commenter noted that compressors can be moved on and off location during a year. The commenter stated that assuming the compressor operated for the entire year could result in inaccurate data. The commenter noted that adjustment of operating hours is allowed under subpart W for pneumatic devices, pneumatic pumps, and equipment leaks and improves the accuracy of the emissions estimated.</P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA reviewed the comments and agreed that changes to allow adjustment of operating hours and pollutant mole fractions when applying the CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                         emission factors to compressors at onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities were warranted. These types of adjustments are already allowed for pneumatic devices, pneumatic pumps, and equipment leaks. Allowing this type of flexibility improves the emissions calculation methodology for compressors, consistent with section II.B. of this preamble, and also improves the accuracy of the emissions estimated from compressors at onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities.
                    </P>
                    <HD SOURCE="HD3">4. Compressors Routed to Controls</HD>
                    <P>
                        The EPA is finalizing several revisions related to centrifugal and reciprocating compressors routed to controls as described in this section. The EPA received only minor comments regarding centrifugal and reciprocating compressors routed to controls. See the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
                    </P>
                    <P>
                        Centrifugal and reciprocating compressors are the only sources for which capture for fuel use and thermal oxidizers currently are specifically listed as dispositions for emissions that would otherwise be vented (see 40 CFR 98.233(o) and (p) introductory text). The EPA's intent with the provisions is to differentiate flares, which are combustion devices that combust waste gases without energy recovery (per 40 CFR 98.238), from combustion devices with energy recovery, including for fuel use. However, some thermal oxidizers combust waste gases without energy recovery and therefore may instead meet the subpart W definition of flare. Consistent with section II.D. of this preamble, in order to clarify and emphasize that the EPA's intent is generally to treat emissions routed to flares and combustion devices other than flares consistently, we are finalizing as proposed removal of the references to fuel use and to thermal oxidizers in 40 CFR 98.233(o) and (p) and 40 CFR 98.236(o) and (p). Also, we are finalizing as proposed to define “routed to combustion” in 40 CFR 98.238 to specify the types of non-flare combustion equipment for which reporters would be expected to calculate emissions. In particular, for the Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural Gas Distribution industry segments, 
                        <PRTPAGE P="42158"/>
                        “routed to combustion” means the combustion equipment specified in 40 CFR 98.232(c)(22), (i)(7), and (j)(12), respectively (
                        <E T="03">i.e.,</E>
                         the combustion equipment for which emissions must be calculated per 40 CFR 98.233(z)). For all other industry segments, “routed to combustion” means the stationary combustion sources subject to subpart C. The final definition of “routed to combustion” applies for all subpart W emission sources for which that term appears (
                        <E T="03">e.g.,</E>
                         natural gas driven pneumatic pumps).
                    </P>
                    <HD SOURCE="HD3">5. Reporting of Compressor Activity Data</HD>
                    <P>
                        The EPA is finalizing as proposed several amendments to remove redundancy, consistent with section II.D. of this preamble. The EPA received only supportive comments regarding revisions to remove reporting redundancy for centrifugal and reciprocating compressors. See the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
                    </P>
                    <P>We are finalizing the removal of some data elements that are redundant between 40 CFR 98.236(o)(1) and (2) for centrifugal compressors and between 40 CFR 98.236(p)(1) and (2) for reciprocating compressors. Specifically, current 40 CFR 98.236(o)(1)(vi) and 40 CFR 98.236(p)(1)(viii) require reporters to indicate which individual compressors are part of a manifolded group of compressor sources, and current 40 CFR 98.236(o)(1)(vii) through (ix) and 40 CFR 98.236(p)(1)(ix) through (xi) require reporters to indicate whether individual compressors have compressor sources routed to flares, vapor recovery, or combustion. However, current 40 CFR 98.236(o)(2)(ii)(A) and 40 CFR 98.236(p)(2)(ii)(A) require the same information for each compressor leak or vent rather than by compressor. The information collected for each leak or vent is more detailed and is the information used for emissions calculations. Therefore, the EPA is finalizing the removal of the redundant reporting requirements in existing 40 CFR 98.236(o)(1)(vi) through (ix) and existing 40 CFR 98.236(p)(1)(viii) through (xi), consistent with section II.B. of this preamble.</P>
                    <HD SOURCE="HD2">P. Equipment Leak Surveys</HD>
                    <P>
                        Subpart W reporters are currently required to quantify emissions from equipment leaks using the calculation methods in 40 CFR 98.233(q) (equipment leak surveys) and/or 40 CFR 98.233(r) (equipment leaks by population count). The equipment leak survey method currently uses the count of leakers detected with one of the subpart W leak detection methods in 40 CFR 98.234(a), subpart W leaker emission factors, and operating time to estimate the emissions from equipment leaks. The current leaker emission factors applicable to onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities are found in existing table W-1E to subpart W. These leaker emission factors are based on the EPA's 
                        <E T="03">Protocol for Equipment Leak Emission Estimates</E>
                         published in 1995 (Docket ID. No. EPA-HQ-OAR-2009-0927-0043), also available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234. The leaker emission factors are provided for components in gas service, light crude service, and heavy crude service that are found to be leaking via several different screening methods. In addition to being component- and service-specific, subpart W currently provides two different sets of leaker emission factors: one based on leak rates for leaks identified by Method 21 (see 40 CFR part 60, appendix A-7) using a leak definition of 10,000 ppm and one based on leak rates for leaks identified by Method 21 using a leak definition of 500 ppm. Currently, the other leak screening methods provided in subpart W (OGI, infrared laser beam illuminated instrument, and acoustic leak detection device) use the leaker emission factors based on Method 21 data with a leak definition of 10,000 ppm.
                    </P>
                    <P>In this final rule, consistent with the 2023 Subpart W Proposal, we are making several technical changes to the equipment leak survey provisions for the equipment leak emission source. The key changes included in this final rule are providing updated and new leaker emission factors, revising and providing new leaker calculation methodologies, and providing better alignment with the NSPS OOOOa and NSPS OOOOb as well as EG OOOOc survey requirements.</P>
                    <HD SOURCE="HD3">1. Revisions and Addition of Default Leaker Emission Factors</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        We are finalizing as proposed to amend the leaker emission factors in existing table W-1E (final table W-2) to subpart W for onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities to update the Method 21 emission factors as well as include separate emission factors for leakers detected with OGI, consistent with section II.B. of this preamble. We are finalizing as proposed to revise the emission factors using study data from Zimmerle 
                        <E T="03">et al.</E>
                         (2020) and Pacsi 
                        <E T="03">et al.</E>
                         (2019). The Zimmerle 
                        <E T="03">et al.</E>
                         (2020) study contains hundreds of quantified leaks detected using OGI. The Pacsi 
                        <E T="03">et al.</E>
                         (2019) study also contains hundreds of equipment leak measurements from sites that were screened using Method 21 with a leak definition of 10,000 ppm and 500 ppm as well as OGI. We are finalizing the use of these studies as the basis for the final emission factors because they included recent measurements of subpart W-specified equipment leak components from both oil and gas production and gathering and boosting sites in geographically diverse locations.
                    </P>
                    <P>
                        Numerous equipment leak studies,
                        <SU>67</SU>
                        <FTREF/>
                         including Pacsi 
                        <E T="03">et al.</E>
                         (2019) have found that OGI detects fewer leaks that are on average larger in size than those detected by EPA Method 21. Specifically, the average leaker emission factor determined from OGI leak detection surveys is often a factor of two or more larger than leaker emission factors determined when using Method 21 leak detection surveys. Therefore, the application of the same leaker emission factor to leaking components detected with OGI and Method 21 with a leak definition of 10,000 ppm, as is currently done in subpart W, likely understates the emissions from leakers detected with OGI. Using the Pacsi 
                        <E T="03">et al.</E>
                         (2019) study data, we estimate that the leaks detected by OGI are 1.63 times larger than leaks detected by Method 21 at a 
                        <PRTPAGE P="42159"/>
                        leak definition of 10,000 ppm and 2.81 times larger than leaks detected by Method 21 at a leak definition of 500 ppm. As noted, the Pacsi 
                        <E T="03">et al.</E>
                         (2019) study provides data on leaks detected by Method 21 at a leak definition of 10,000 ppm and 500 ppm as well as OGI data, however, the sample size of leaks screened in the Pacsi 
                        <E T="03">et al.</E>
                         (2019) study with Method 21 is smaller than those screened with OGI, particularly when combining the OGI data from Pacsi 
                        <E T="03">et al.</E>
                         (2019) with the Zimmerle et al. (2020) data. The combined OGI dataset from Pacsi 
                        <E T="03">et al.</E>
                         (2019) and Zimmerle et al. (2020) contains more than 700 measurements from leaks detected with OGI. Emission factors using these data are derived for each combination of well site type (
                        <E T="03">e.g.,</E>
                         gas or oil) and component type (
                        <E T="03">e.g.,</E>
                         valve). The more than 700 measurements in the combined OGI dataset results in an average of 44 measurements for each combination of well site type (
                        <E T="03">e.g.,</E>
                         gas or oil) and component type (
                        <E T="03">e.g.,</E>
                         valve). In contrast, the Pacsi 
                        <E T="03">et al.</E>
                         study has nearly 300 measurements for leaks detected using Method 21 at a leak definition of 500 ppm and 140 measurements for leaks detected using Method 21 at a leak definition of 10,000 ppm, which results in averages of 21 measurements and 10 measurements for each combination of site type and component type, respectively.
                    </P>
                    <FTNT>
                        <P>
                            <SU>67</SU>
                            See, 
                            <E T="03">e.g.,</E>
                             ERG (Eastern Research Group, Inc.) and Sage (Sage Environmental Consulting, LP). 
                            <E T="03">City of Fort Worth Natural Gas Air Quality Study: Final Report.</E>
                             July 13, 2011, available at 
                            <E T="03">https://www.fortworthtexas.gov/departments/development-services/gaswells/air-quality-study/final;</E>
                             Allen, D.T., 
                            <E T="03">et al.</E>
                             “Measurements of methane emissions at natural gas production sites in the United States.” 
                            <E T="03">Proceedings of the National Academy of Sciences of the United States of America,</E>
                             Vol. 110, no. 44. pp. 17768-17773, October 29, 2013, available at 
                            <E T="03">http://dept.ceer.utexas.edu/methane/study.</E>
                             Docket ID. No. EPA-HQ-OAR-2014-0831-0006; Pacsi, A. P., 
                            <E T="03">et al.</E>
                             “Equipment leak detection and quantification at 67 oil and gas sites in the Western United States.” 
                            <E T="03">Elem Sci Anth,</E>
                             7: 29, available at 
                            <E T="03">https://doi.org/10.1525/elementa.368.</E>
                             2019; Zimmerle, D., 
                            <E T="03">et al.</E>
                             “Methane Emissions from Gathering Compressor stations in the U.S.” 
                            <E T="03">Environmental Science &amp; Technology</E>
                             2020, 54(12), 7552-7561, available at 
                            <E T="03">https://doi.org/10.1021/acs.est.0c00516.</E>
                             The documents are also available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        For OGI, we are finalizing leaker emission factors that were developed using the combined data from Pacsi 
                        <E T="03">et al.</E>
                         (2019) and Zimmerle 
                        <E T="03">et al.</E>
                         (2020) by site type (
                        <E T="03">i.e.,</E>
                         gas or oil). Equipment leaks are inherently variable; therefore, sample size is important when seeking to derive representative equipment leak emission factors. Therefore, in this final rule, we used the OGI data and the ratio between OGI and the Method 21 at a leak definition of 10,000 ppm and a leak definition of 500 ppm (
                        <E T="03">i.e.,</E>
                         1.63 and 2.81, respectively) measurements to derive the final emission factors for Method 21 at both leak definitions. The precise derivation of the final emission factors is discussed in more detail in the subpart W TSD, available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                    </P>
                    <P>At onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities, very few facilities report using infrared laser beam illuminated instruments or acoustic leak detection devices to conduct equipment leak surveys for the purposes of subpart W and there are no data available to develop leaker emission factors specific to these methods. Based on our understanding and our review of comments received on the 2023 Subpart W Proposal relative to the use of these alternative methods, we expect that their leak detection thresholds will be most similar to OGI, so that the average emissions per leak identified by these alternative methods will be similar to the emissions estimated using the final OGI leaker factors. Therefore, we are finalizing as proposed that, if other leak survey methods including illuminated laser beam or acoustic leak devices are used to conduct leak surveys, the final OGI leaker emission factors in final table W-2 to subpart W must be used to quantify the emissions from the leaks identified using these other monitoring methods.</P>
                    <P>For onshore petroleum and natural gas gathering and boosting facilities, we note that subpart W currently specifies that all components should be considered to be in gas service consistent with the language in 40 CFR 98.233(q)(2)(iv); thus, under the final rule the gas service factors from final table W-2 should be applied to the count of equipment leak components consistent with the leak detection method used.</P>
                    <P>For onshore petroleum and natural gas production facilities, we are finalizing as proposed to amend 40 CFR 98.233(q)(2)(iii) to state that onshore petroleum and natural gas production facilities must use the appropriate default whole gas leaker emission factors consistent with the well type (rather than the component-level service type), where components associated with gas wells are considered to be in gas service and components associated with oil wells are considered to be in oil service as listed in final table W-2 to subpart W. After consideration of comments received on the proposed rule as discussed further in section III.P.1.b. of this preamble, we are also adding clarifying edits in this final rule to the footnotes of final table W-2. One of these edits removes footnote 1, which included a specification to use the gas service emission factors for multi-phase flow. This footnote 1 no longer applies. Consistent with the derivation of the default leaker emission factors, the default leaker emission factors must be applied by site type for onshore petroleum and natural gas production facilities, while onshore petroleum and natural gas gathering and boosting sites must use the gas service default leaker emission factors. The edits also clarify that the default leaker emission factors for the open-ended line (OEL) component type includes the blowdown valve and isolation valve leaks when using the population count emission factor approach specified in 40 CFR 98.233(o)(10)(iv) or (p)(10)(iv).</P>
                    <P>
                        As described previously, our analysis of measurement study data from onshore production and gathering and boosting facilities demonstrates that the OGI screening method finds fewer and larger leaks in terms of emission rate than EPA Method 21 (
                        <E T="03">i.e.,</E>
                         each screening method finds a different, but overlapping, subset of the existing leaks). Consequently, the leaker emission factors derived using measurement data from the OGI screening method are larger than those derived using the measurement data from Method 21 screening method. We expect that the leaker emission factors for other industry segments that are based on measurements of Method 21-identified leaks may similarly underestimate the emissions from leaking equipment when OGI (or other alternative methods besides Method 21) are used to detect the leaks. We are finalizing as proposed the application of the ratio between OGI data and Method 21 at a leak definition of 10,000 ppm identified from the Pacsi 
                        <E T="03">et al.</E>
                         (2019) study data in the onshore production and gathering and boosting industry segments, a value of 1.63, to the leaker emission factors for the other subpart W industry segments as a means to estimate and finalize a separate OGI emission factor set. Analogous to the changes in final table W-2 to subpart W for the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments, this results in the addition of final emission factor sets specific to OGI, infrared laser beam illuminated instrument, or acoustic leak detection device screening methods. The final emission factor sets are included in tables W-4 and W-6 for the Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, LNG Storage, LNG Import and Export Equipment, and Natural Gas Distribution industry segments. A detailed description of the final emission factors is provided in the subpart W TSD, available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234. After consideration of comments, we are finalizing updated provisions to those proposed to provide that facilities reporting to the Onshore Natural Gas Transmission Compression or Underground Natural Gas Storage industry segments may use the concentration of CH
                        <E T="52">4</E>
                         or CO
                        <E T="52">2</E>
                         in the THC of the feed natural gas in lieu of the default concentrations provided in 
                        <PRTPAGE P="42160"/>
                        equation W-30 when quantifying equipment leak emissions using Calculation Method 1. The use of facility-specific composition data for the concentration of CH
                        <E T="52">4</E>
                         or CO
                        <E T="52">2</E>
                         in the THC feed of natural gas instead of using default values is expected to increase the accuracy of the emission estimates.
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to the equipment leak survey default leaker emission factors.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters noted that there were inconsistencies with the preamble to the 2023 Subpart W Proposal as well as proposed 40 CFR 98.233(q)(2)(iii) and (iv) and the footnote 1 to table W-2 to subpart W, which says, “For multi-phase flow that includes gas, use the gas service emission factors.” In the preamble to the 2023 Subpart W Proposal and in the proposed regulatory text, it says that emission factors should be applied by well site type for production facilities, where components at gas wells are considered to be in gas service and components at oil wells are considered to be in oil service. The proposed rule also provided that components at gathering and boosting sites should be considered to be in gas service. Further, commenters requested that the EPA clarify in footnote 2 to table W-2 that if an entity elects to use as-found measurements to estimate emissions from isolation valve and blowdown valve leakage, that leaks detected from these sources should be calculated pursuant to paragraph (p) or (o) rather than paragraph (q). Finally, commenters requested that the EPA clarify in footnote 2 to table W-2 how dry seal vents are intended to be reported when a gathering and boosting or processing site elects to use population emission factors for compressor venting.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We agree with commenters that our intent, which is consistent with the derivation of the default leaker emission factors, is for production facilities to apply component-level emission factors based on the well site type and for components at gathering and boosting facilities to use the gas service default leaker emission factors. The reference to footnote 1 in the context of default leaker factors in final table W-2 to subpart W has been removed. We also agree with the commenters that clarification is needed in footnote 2 and have edited the footnote in the final rule to state that the OEL component type includes the blowdown valve and isolation valve leaks when using the population count emission factor approach specified in 40 CFR 98.233(o)(10)(iv) or (p)(10)(iv). Finally, in response to the request for clarification regarding dry seals, we note that there is no emission factor for dry seals in the existing rule, which is unchanged by this final rulemaking, and thus emissions associated with dry seals are not required to be reported.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters requested that the EPA allow the use of annual average GHG mole fraction GHGi in equations W-30 and W-32A as allowed in equation W-1A for natural gas pneumatic devices. Commenters explained that this would better align equipment leak calculations with other calculations of subpart W and be consistent with the initiative of capturing empirical data.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We agree with the commenter's suggestion to allow for the use of the actual concentration of CH
                        <E T="52">4</E>
                         or CO
                        <E T="52">2</E>
                         in the calculation of equipment leak emissions in 40 CFR 98.233(q) and (r) as we expect that when utilized the accuracy of the resulting emissions will increase. Therefore, we are finalizing amendments to the variable for the concentration of greenhouse gases, GHGi, in the definition of the variables for equations W-30 and W-32A to provide the option of using the existing default concentrations or the actual concentration of methane or carbon dioxide in the THC of the feed natural gas.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Several commenters opposed the separate OGI default leaker emission factors and noted that the derived emission factors are much higher for this leak survey method than for EPA Method 21. Other commenters expressed support for the separate OGI default leaker emission factors and stated that they believe the resulting emissions estimates will be more accurate.
                    </P>
                    <P>
                        Commenters opposing the separate OGI default leaker emission factors asserted that their inclusion disincentivizes the use of OGI. Commenters note that OGI was determined to be the best system for emission reductions (BSER) in the NSPS OOOOb and EG OOOOc rules, yet the proposed default leaker emission factors would penalize its use for emissions reporting. Commenters note that there were other sources of equipment leak data that could be considered when developing leaker emission factors including annual leak reports from the state of Colorado or the Environmental Partnership. Some commenters noted that the Pacsi 
                        <E T="03">et al.</E>
                         (2019) study was limited to four geographical regions, a single OGI camera make and model, and did not consider operator training. Another commenter stated that the Pacsi 
                        <E T="03">et al.</E>
                         (2019) study concluded, “The most common EPA estimation method for greenhouse gas emission reporting for equipment leaks, which is based on major site equipment counts and population-average component emission factors, would have overestimated equipment leak emissions by 22 percent to 36 percent for the sites surveyed in this study as compared to direct measurements of leaking components because of a lower frequency of leaking components in this work than during the field surveys conducted more than 20 years ago to develop the current EPA factors.” Some commenters stated that the EPA has selectively updated certain emission factors to inflate emissions in response to the Inflation Reduction Act and fiscal implications for oil and gas companies. Commenters recommended that the EPA maintain the OGI and Method 21 with a leak definition of 10,000 ppm default leaker emission factor set currently in the rule.
                    </P>
                    <P>Commenters also opposed the use of the “OGI enhancement factor,” which was a ratio of the average leak rate size surveyed using OGI to EPA Method 21 to provide the updated Method 21 default leaker emission factors for onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments.</P>
                    <P>
                        <E T="03">Response:</E>
                         The proposed default leaker emission factors for the onshore natural gas production and onshore gathering and boosting facilities are based on the combination of data from publicly available and peer reviewed studies including the Pacsi 
                        <E T="03">et al.</E>
                         (2019) and Zimmerle 
                        <E T="03">et al.</E>
                         (2020) studies. The combined OGI dataset from Pacsi 
                        <E T="03">et al.</E>
                         (2019) and Zimmerle 
                        <E T="03">et al.</E>
                         (2020) contains more than 700 measurements from leaks detected with OGI. We derived OGI emission factors by site type (
                        <E T="03">i.e.,</E>
                         gas or oil) directly from the combination of these data. The Pacsi 
                        <E T="03">et al.</E>
                         (2019) dataset includes equipment leaks surveyed with Method 21 at both leak definitions, but the sample sizes are smaller. Thus, we derived the ratio between OGI and the Method 21 at a leak definition of 10,000 ppm and a leak definition of 500 ppm (
                        <E T="03">i.e.,</E>
                         1.63 and 2.81, respectively) and applied the ratio to the OGI emission factors to derive the proposed emission factors for Method 21 at both leak definitions. The derivation of the separate emission factor sets seeks to utilize the most robust dataset of publicly available data to develop these separate leaker emission factors, consistent with findings in multiple studies that the 
                        <PRTPAGE P="42161"/>
                        average size of the leaks detected by OGI are larger than those detected by EPA Method 21. This approach is not intended to disincentivize any survey method and, furthermore as discussed below, our expectation is that the approach finalized in this rulemaking will yield similar equipment leak emission estimates regardless of the selected method. We maintain that the separate OGI emission factors are appropriate, accurate, and based on the best available data and we are finalizing them, as proposed.
                    </P>
                    <P>
                        Commenters mentioned that thousands of equipment leaks were reported to the state of Colorado. We have reviewed the data from the state of Colorado that are publicly available, and agree that many more leaks were reported statewide than are detected/measured in the Pacsi 
                        <E T="03">et al.</E>
                         (2019) and Zimmerle 
                        <E T="03">et al.</E>
                         (2020) studies. Similarly, we have reviewed the data from the Environmental Partnership that are publicly available and find this it could be useful for understanding leak incident rate for member companies. However, the publicly available data from Colorado and the Environmental Partnership do not contain the necessary data to derive an emission factor as provided in the Pacsi 
                        <E T="03">et al.</E>
                         (2019) and Zimmerle 
                        <E T="03">et al.</E>
                         (2020) studies used by the EPA including: component-level leak rates, major equipment, site level information, survey method, quantification method, and leak rate.
                    </P>
                    <P>
                        Additionally, we note that some commenters appear to be misrepresenting conclusions from the Pacsi 
                        <E T="03">et al.</E>
                         (2019) by stating that the existing default method would overestimate the emissions by 22 to 36 percent and this does not support updated leaker emission factors. We note that in this conclusion presented in the Pacsi 
                        <E T="03">et al.</E>
                         (2019) study, study authors are comparing the existing population count method results to the study results—not comparing the results of the subpart W leaker method with the study results.
                    </P>
                    <P>
                        As described in this preamble, the purpose of the OGI enhancement factor is to ensure that irrespective of the survey method, the resulting emissions estimated using the default leaker emission factors represent the emission inventory total as there are inherent differences in the leaks detected when using different survey methods. We have undertaken additional analysis to demonstrate that the final emission factors for Method 21 at a leak definition of 500 ppm, Method 21 at a leak definition of 10,000 ppm, and the OGI emission factors and the survey method specific undetected leak factors successfully estimate the study emissions total. The details of this analysis are presented in the 
                        <E T="03">Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for Data Elements Under the Greenhouse Gas Reporting Rule; Final Rule—Petroleum and Natural Gas Systems,</E>
                         which is available in the docket for this rulemaking (Docket ID No. EPA-HQ-OAR-2023-0234). In summary, the analysis uses the Pacsi 
                        <E T="03">et al.</E>
                         (2019) activity data (
                        <E T="03">i.e.,</E>
                         number of leakers by site type, component type, and survey method) with the final emission factors and undetected leak factor to estimate emissions. The analysis demonstrates that using the proposed emission factors and the undetected leak factor yield emissions that are between 1 and 10 percent of the study total emissions for all survey methods. This analysis supports the use of these factors, and as discussed elsewhere in the preamble to the final rule and in the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         (available in Docket ID. No. EPA-HQ-OAR-2023-0234), the use of the undetected leak factors.
                    </P>
                    <P>Concerning comments about OGI being determined as BSER for the NSPS, we note that BSER determinations consider technical feasibility, cost, non-air quality health and environmental impacts, and energy requirements. To further the programmatic goals of subpart W, we considered the best available data by which to derive default emission factors to ensure accuracy of the resulting emissions calculations. We find that the purposes of the NSPS and subpart W are inherently different, as one is a standard setting program while the other is a reporting program. Thus, while the determination that OGI is BSER for the NSPS may influence facilities' decision to utilize this method, it does not have bearing on how emissions are quantified under this reporting program.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters noted that the Zimmerle 
                        <E T="03">et al.</E>
                         (2020) study showed that emissions from compressor type components have higher leak rates due to vibration. Commenters noted that the EPA did not distinguish between components associated with or not with compressors in its development of the default leaker emission factors. As a consequence, the average proposed emission factors seem to include compressor-related components, which would overstate emissions from the non-compressor related components. Commenters requested that the EPA carefully review the emission factors and consider including compressor related components in the breakdown of the leaker factors.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We agree with commenters that the average leak sizes in the Zimmerle 
                        <E T="03">et al.</E>
                         (2020) and Pacsi 
                        <E T="03">et al.</E>
                         (2019) studies were larger for components associated with compressor major equipment. As described previously, the default leaker emission factors were derived by component type (
                        <E T="03">e.g.,</E>
                         valves), site type (
                        <E T="03">i.e.,</E>
                         gas or oil), and survey method (
                        <E T="03">e.g.,</E>
                         OGI) and as noted by commenters did not consider the component's association with compressor or non-compressor equipment. In order to evaluate the impact of considering the association with compressor or non-compressor equipment in the development of default leaker emission factors, we conducted additional analysis. The Zimmerle 
                        <E T="03">et al.</E>
                         (2020) and Pacsi 
                        <E T="03">et al.</E>
                         (2019) studies both include attribution of leak measurements to major equipment categories (
                        <E T="03">i.e.,</E>
                         compressor, non-compressor, tank) or to major equipment (
                        <E T="03">e.g.,</E>
                         compressor, flare, separator), respectively. Therefore, we have utilized this study reported information to further disaggregate our proposed default leaker emission factors into compressor and non-compressor emission factor sets such that the resulting factors are by component type, site type, survey method, and whether they are associated with a compressor or non-compressor, as appropriate. We then applied these emission factors to the Pacsi 
                        <E T="03">et al.</E>
                         (2019) study activity data (
                        <E T="03">i.e.,</E>
                         number of leakers by site type, component type, survey method, and association with compressor or non-compressor major equipment) and undetected leak factor to estimate emissions. The analysis demonstrates that using the compressor and non-compressor emission factors and the undetected leak factor yield emissions that are between 3 and 14 percent lower than the study total emissions for all survey methods. As noted in the previous comment/response in this section of the preamble, we performed an analogous analysis using the proposed default leaker emission factors and found that the estimated emissions were between 1 and 10 percent of the study total. Therefore, the use of the separate compressor and non-compressor emission factors did not result in improved accuracy and tends to further underestimate the emissions when compared to the use of the proposed emission factors. The details 
                        <PRTPAGE P="42162"/>
                        of this analysis are presented in the Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for Data Elements Under the Greenhouse Gas Reporting Rule; Final Rule—Petroleum and Natural Gas Systems, which is available in the docket for this rulemaking (Docket ID No. EPA-HQ-OAR-2023-0234). We suspect that one reason the separate compressor and non-compressor emission factors do not perform better than the proposed factors is due to the further disaggregation of the leak survey and measurement data from the underlying datasets eroding the sample size that informs the emission factors. This means that any accuracy that may be gained by disaggregating emission factors into compressor or non-compressor categories is offset by the reduction in sample size for the development of such a factor. Based on the results of this analysis, we are finalizing the default leaker factors based on component type, site type, and survey method only basis, as proposed.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters stated that they could not determine how the proposed default leaker emission factors for onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting had been developed. Specifically, one commenter performed a side-by-side comparison of the default leaker emission factors in the Zimmerle 
                        <E T="03">et al.</E>
                         (2020) and Pacsi 
                        <E T="03">et al.</E>
                         (2019) studies and those included in the 2023 Subpart W Proposal, noting that they could not match the values.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         A detailed explanation and tables were included in the TSD for the proposed rule explaining how the emission factors were derived. We note that the Zimmerle 
                        <E T="03">et al.</E>
                         (2020) study provided separate emission factors for compressor and non-compressor components and as noted in the previous response and explained in the TSD, the EPA has combined all of the Zimmerle 
                        <E T="03">et al.</E>
                         (2020) data with the Pacsi 
                        <E T="03">et al.</E>
                         (2019) data to develop the OGI emission factor set. We also note that we consider the Zimmerle 
                        <E T="03">et al.</E>
                         (2020) data to be for gas sites only, consistent with the categorization of onshore petroleum and natural gas gathering and boosting equipment in subpart W. We used the study reported site type (
                        <E T="03">e.g.,</E>
                         oil or gas) in the Pacsi 
                        <E T="03">et al.</E>
                         (2019) data to determine the service type for the purposes of aggregating data by site type when developing the default leaker emission factors. So, there may be differences in the precise values because of the assumptions made when combining the study data for the purposes of developing emission factors by component and site type. However, we find that the study published emission factors are in general agreement with those derived by the EPA and our assumptions regarding the aggregation of data are documented in the Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for Data Elements Under the Greenhouse Gas Reporting Rule; Final Rule—Petroleum and Natural Gas Systems, which is available in the docket for this rulemaking (Docket ID No. EPA-HQ-OAR-2023-0234).
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters stated that the proposed revisions to leaker emission factors are based on studies for OGI at onshore production and gathering and boosting facilities and are not relevant to midstream (
                        <E T="03">e.g.,</E>
                         transmission compression, underground storage) or downstream (
                        <E T="03">e.g.,</E>
                         natural gas distribution) sources. Commenters added that the creation of the OGI enhancement factor is not reasonable and is not based on technical data supporting applicability to sources downstream of the onshore production and gathering and boosting facilities. Some commenters recommended that the current OGI leaker emission factors should be retained, as applicable, since it is inappropriate to apply an “enhancement” based on analysis of a small dataset from the upstream segment that includes significant disparities in both the operation of equipment (
                        <E T="03">e.g.,</E>
                         pressure, CH
                        <E T="52">4</E>
                         content) and leak detection environment (
                        <E T="03">e.g.,</E>
                         wind conditions). Other commenters recommended that the EPA should consider additional prospective studies and data gathered using OGI and other leak testing methods in other segments of the natural gas supply chain and recommended that the EPA reconsider the OGI enhancement factors and, if appropriate, re-propose them in the future when more data are available.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         As demonstrated in the record, we have long contemplated and evaluated study data that demonstrates that there are methodological differences that result in the average leak detected by OGI being higher in magnitude than the leaks detected using Method 21. During the 2016 leaker rule amendments we evaluated a number of studies for equipment leaks in order to inform emission factor updates (see the 2016 TSD; Docket ID. No. EPA-HQ-OAR-2015-0764-0066). These studies included:
                    </P>
                    <P>• City of Fort Worth Natural Gas Air Quality Study (ERG and Sage, 2011);</P>
                    <P>
                        • Measurements of Methane Emissions at Natural Gas Production Sites in the United States, Supporting Information (Allen 
                        <E T="03">et al.,</E>
                         2013);
                    </P>
                    <P>
                        • Methane Emissions from Natural Gas Compressor Stations in the Transmission and Storage Sector: Measurements and Comparisons with the EPA Greenhouse Gas Reporting Program Protocol (Subramanian 
                        <E T="03">et al.,</E>
                         2015).
                    </P>
                    <P>In the 2016 TSD, we identified, analyzed and discussed the overall finding that equipment leaks detected with OGI were higher than those detected using Method 21. For reference, a summary of our analyses and conclusions at the time are included here:</P>
                    <P>
                        • For onshore production and gathering and boosting, we compared the data in the 2011 Fort Worth study (ERG and Sage, 2011) and Allen 
                        <E T="03">et al.</E>
                         (2013) studies, which are OGI-based fugitive emissions studies and which appear to yield higher leaker emission factors than the EPA Method 21-based data presented in the 1995 EPA Protocol (the basis for the existing subpart W leaker emission factors for Onshore Production and Gathering and Boosting). In order to better understand the variability in leaker emission factors from different studies, we conducted Monte Carlo analyses using the study data. Based on these analyses, random samples of 30 leaking components can be expected to yield average leaker emission factors that vary by a factor of 2 to 3 and samples of 100 leaking components can expected to yield average leaker emission factors that vary by a factor 1.5 to 2. Although this does not directly show that OGI-determined leaker emission factors are necessarily different than EPA Method 21-determined leaker emission factors, if leak rate variability were the only reason for the differences in leaker emission factors, we would expect that the EPA Method 21 leaker emission factors would be higher than the OGI leaker emission factors approximately 50 percent of the time. The fact that the OGI leaker emission factors are consistently higher than the EPA Method 21 leaker emission factors (using a leak threshold of 10,000 ppmv) in essentially every case provides evidence that variability alone does not fully explain the data and that OGI “visualized” leaks are generally larger than leaks that have measured EPA Method 21 concentrations above 10,000 ppmv.
                    </P>
                    <P>
                        • We also discussed seeing similar results for the Onshore Natural Gas Transmission Compression industry segment. We compared leaker emission factors derived from OGI-based study (Subramanian 
                        <E T="03">et al.,</E>
                         2015) and the EPA 
                        <PRTPAGE P="42163"/>
                        Method 21-based study (Clearstone, 2002; Clearstone 2007) conducted at Onshore Natural Gas Transmission Compression facilities. As shown in the 2016 TSD, not considering the data where the number of measurements were 10 or fewer, the OGI-based leaker emission factor was larger than the EPA Method 21 (at 10,000 ppmv) leaker emission factor for five of the six components, and the one component (valves on compressors) where the OGI-based measurement was smaller, the leaker emission factors are essentially identical. Thus, these data support the conclusions drawn from the production data. Specifically, OGI-based and EPA Method 21 (at 10,000 ppmv) leaker emission factors usually compare within the expected range of a values considering the high variability of individual measurements. Additionally, OGI-based leaker emission factors are consistently larger than EPA Method 21 (at 10,000 ppmv) leaker emission factors, suggesting that variability alone does not explain the differences observed and that the methodological differences in how leaks are identified are also likely to contribute to the consistently higher OGI-based leaker emission factors.
                    </P>
                    <P>
                        Since the 2016 final rule, the EPA has obtained additional data that demonstrate the same finding—that OGI detects larger leaks than EPA Method 21. First, we note that gathering and boosting sites could be considered similar to transmission compression sites in that they have many compressors and associated pipeline connections. As described in the subpart W 2023 proposed rule TSD, the Zimmerle 
                        <E T="03">et al.</E>
                         (2020) study was performed at gathering and boosting sites where OGI surveys were performed to detect leaks, which were then quantified. When comparing the leaker emission factors developed using the Zimmerle 
                        <E T="03">et al.</E>
                         (2020) study to those in the existing subpart W for Method 21 at either leak definition, the OGI leaker emission factors are higher for all component types. On the basis of the similarities in operating equipment between gathering and boosting sites and transmission compression sites and the observations of average leak sizes in the Zimmerle 
                        <E T="03">et al.</E>
                         (2020) data as compared to Method 21, we continue to expect that these findings apply across the supply chain.
                    </P>
                    <P>
                        Further, the Pacsi 
                        <E T="03">et al.</E>
                         (2019) study that compared OGI and Method 21 side-by-side at multiple production and gathering and boosting sites supports the conclusion that OGI and Method 21 detect different populations of leakers, and that generally OGI detects larger leaks. Considering our past review of this issue, including reviewing data specific to midstream industry segments, and the additional data we have obtained since the 2016 final rule, we are promulgating, as proposed, separate OGI emission factors for all industry segments that are required or elect to quantify emissions using the leaker method.
                    </P>
                    <HD SOURCE="HD3">2. Addition of Undetected Leak Factor for Leaker Emission Estimation Methods</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        Subpart W currently provides various screening methods for detecting leaking components in 40 CFR 98.234(a). Each method includes a unique instrument and associated procedure by which leaks are detected. Variability inherently exists in each method's ability to detect leaks, which can be attributed to reasons associated with the instrument, leak detection procedures, the operator or site conditions. For the 2023 Subpart W Proposal, we reviewed recent study data from Pacsi 
                        <E T="03">et al.</E>
                         (2019) in which multiple leak detection methods, including OGI and Method 21, were deployed alongside one another at the same sites. This study demonstrates that there are undetected leaks for each method. Based on the Pacsi 
                        <E T="03">et al.</E>
                         (2019) study data, OGI observes 80 percent of emissions from measured leaks, Method 21 at a leak definition of 10,000 ppm observes 65 percent of emissions from measured leaks, and Method 21 at leak definition of 500 ppm observes 79 percent of emissions from measured leaks. In order to account for the quantity of emissions that remain undetected by each screening method, we are finalizing as proposed to provide a method specific adjustment factor, k, for the calculation methods used to quantify emissions from equipment leaks using the leaker method in 40 CFR 98.233(q). We are finalizing as proposed that, if other methods including illuminated infrared laser beam or acoustic leak detection devices are used to conduct leak surveys, the final OGI adjustment factor, k, must be used in the calculation to quantify the emissions from the leaks identified using these other monitoring methods. The addition of a method specific adjustment factor under the final rule will improve the accuracy of emissions data, consistent with section II.B. of this preamble. Further detail on the development of the adjustment factor for each of these screening methods is provided in the subpart W TSD, available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to add an undetected leak factor for the leaker emission estimation method.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Some commenters were opposed to the addition of an undetected leak factor, while others expressed support for the addition of this factor.
                    </P>
                    <P>Commenters who were not in favor of the factor stated that including this factor implies that operators are not making efforts to comply with leak detection and repair (LDAR) federal and state regulatory programs. Commenters also stated that instead of imposing an undetected leak factor, the EPA should emphasize proper training relative to the survey methods to ensure the accuracy of the survey results. Some commenters suggested that the EPA remove the undetected leak factor all together while others recommended that the EPA remove the adjustment factor when direct measurement is used to quantify emissions.</P>
                    <P>
                        Commenters stated that leaks were detected at only five “boosting and gathering” sites included in the Pacsi 
                        <E T="03">et al.</E>
                         (2019) study results that are the basis for the undetected leak factor value and thus, development of an undetected leak factor does not accurately represent the entirety of the sector and does not qualify as a statistically significant dataset of empirical data to apply to reporting facilities in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment.
                    </P>
                    <P>
                        Similarly, several commenters stated that the undetected leak factor was developed using data from upstream facilities, which are not representative of the operating equipment (
                        <E T="03">e.g.,</E>
                         pressure, CH
                        <E T="52">4</E>
                         content) and leak detection environment (
                        <E T="03">e.g.,</E>
                         wind conditions) in industry segments downstream of the Onshore Petroleum and Natural Gas Production or Onshore Petroleum and Natural Gas Gathering and Boosting industry segments. Thus, the undetected leak factor should not be applied to emission estimates for those industry segments until such time that sector-specific studies are conducted that demonstrate the applicability of a such a factor to their operations.
                    </P>
                    <P>
                        Some commenters stated that they could not replicate the calculations the EPA used to estimate the undetected leak factor and requested that the EPA provide additional information on the derivation. These commenters also requested that the EPA test their “k” factors by applying to the Method 21 
                        <PRTPAGE P="42164"/>
                        data in order to recalculate the emissions at the site level using study data and confirm if it matches with the measured emissions.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The undetected leak factor is based off the best available data where both OGI and Method 21 detection methods were used and the emissions directly quantified (
                        <E T="03">i.e.,</E>
                         the Pacsi 
                        <E T="03">et al.</E>
                         (2019) study). In our review of OGI and Method 21 equipment leak studies, we note that the performance of the survey method is more aligned with technological and methodological differences rather than the location of the equipment or components. As discussed in section III.P.1.b. of this preamble, when available we have evaluated data of midstream and downstream segments including direct comparisons of OGI and Method 21 data.
                    </P>
                    <P>
                        We have undertaken additional analysis regarding the use of separate OGI emission factors and the undetected leak factor. The details of this analysis are presented in the 
                        <E T="03">Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for Data Elements Under the Greenhouse Gas Reporting Rule; Final Rule—Petroleum and Natural Gas Systems,</E>
                         which is available in the docket for this rulemaking (Docket ID No. EPA-HQ-OAR-2023-0234). In summary, the analysis uses the Pacsi 
                        <E T="03">et al.</E>
                         (2019) activity data (
                        <E T="03">i.e.,</E>
                         number of leakers by site type, component type, and survey method) with the final default leaker emission factors and undetected leak factor to estimate emissions. The analysis demonstrates that using the final default leaker emission factors and the undetected leak factor yields emissions that are within 10 percent of the study total emissions considering leaks identified across all leak survey methods. This analysis demonstrates that the use of the undetected leak factor is necessary to scale surveyed emissions to accurately estimate the actual quantity of emissions in the inventory. We maintain that the use of the undetected leak factor enhances the accuracy of the emissions calculation such that they more accurately represent the total emissions quantity of equipment leaks and we are finalizing the method-specific undetected leak factors, as proposed.
                    </P>
                    <P>
                        We note that commenters requested that the EPA compare the emissions that would be estimated using the final default leaker emission factors and the undetected leak factor at the site level to the measured value from the Pacsi 
                        <E T="03">et al.</E>
                         (2019) study. Concerning this request, we note that the default leaker factors are average study-derived emission factors, and thus we would not expect that the emissions resulting from applying an average default leaker emission factor to a single site with a handful of measurements to match. Equipment leak emissions are highly variable and exhibit lognormal distribution such that the emissions for a single component leak can be an order of magnitude or more higher or lower than the average across a large number of components. The inherent variability in the measurements means there is more uncertainty when applying an emission factor, which can be minimized by increasing sample size in the underlying dataset. In this rule, we provide that surveys must be conducted and reported at the well site or gathering site level, and also aggregated at the facility level. Based on our analysis using the study-level data from Pacsi 
                        <E T="03">et al.</E>
                         (2019), we expect the facility-level aggregation of site level emission estimates to reflect the actual emissions.
                    </P>
                    <P>
                        Some commenters noted that the derivation of the undetected leak factors is unclear. We note that a detailed explanation and tables were included in the TSD for the proposed rule. In order to increase transparency in the record, we are providing additional details regarding derivation in the 
                        <E T="03">Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for Data Elements Under the Greenhouse Gas Reporting Rule; Final Rule—Petroleum and Natural Gas Systems,</E>
                         which is available in the docket for this rulemaking (Docket ID No. EPA-HQ-OAR-2023-0234).
                    </P>
                    <HD SOURCE="HD3">3. Addition of Method To Quantify Emissions Using Direct Measurement</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        As an alternative to the final revised default leaker emission factors, we are also finalizing as proposed in 40 CFR 98.233(q)(1) to provide an option (provided in final 40 CFR 98.233(q)(3)) that would allow reporters to quantify emissions from equipment leak components in 40 CFR 98.233(q) by performing direct measurement of equipment leaks and calculating emissions using those measurement results, consistent with section II.B. of this preamble. The final amendments would provide that facilities with components subject to 40 CFR 98.233(q) can elect to perform direct measurement of leaks using one of the existing subpart W measurement methods in 40 CFR 98.234(b) through (d), such as calibrated bagging or a high volume sampler. To use this option under the final provisions, all leaks identified during a “complete leak detection survey” must be quantified; in other words, reporters could not use leaker emission factors for some leaks and quantify other leaks identified during the same leak detection survey. For the Onshore Petroleum and Natural Gas Production industry segment, final 40 CFR 98.233(q)(1) specifies that a complete leak detection survey is the fugitive emissions monitoring of a well site using a method in 40 CFR 98.234(a) conducted to comply with NSPS OOOOa, NSPS OOOOb, or the applicable EPA-approved state plan or the applicable Federal plan in 40 CFR part 62, or, if the reporter elected to conduct the leak detection survey, a complete survey of all equipment on a single well-pad site. For the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment, final 40 CFR 98.233(q)(1) specifies that a complete leak detection survey is the fugitive emissions monitoring of a compressor station using a method in 40 CFR 98.234(a) conducted to comply with NSPS OOOOa, NSPS OOOOb, or the applicable EPA-approved state plan or the applicable Federal plan in 40 CFR part 62, or, if the reporter elected to conduct the leak detection survey, a complete survey of all equipment at a “gathering and boosting site” (and we are finalizing amendments to define this term in 40 CFR 98.238, as described in section III.D. of this preamble). For downstream industry segments (
                        <E T="03">e.g.,</E>
                         Onshore Natural Gas Transmission Compression), a complete leak detection survey is facility-wide, and therefore, the election to perform direct measurement of leaks is also required to be facility-wide. In other words, this option allows the use of measurement data directly when all leaks identified are quantitatively measured. After consideration of comments, under the final rule we are finalizing the addition of provisions for substituting measurement data for components that require elevating the measurement personnel more than 2 meters above the surface and a lift is unavailable at the site or would pose immediate danger to measurement personnel performing the direct measurement using one of the methods in 40 CFR 98.234(a). These final provisions will allow facilities to substitute measurement data only for components meeting these criteria with the component-specific and service-specific default leak rate in final tables W-2, W-4, or W-6, as applicable. We are also updating from proposal the term “well-pad” in proposed 98.233(q)(1)(vii)(D) to the newly defined 
                        <PRTPAGE P="42165"/>
                        “well-pad site” term in the final provision (see section III.D. of this preamble) to clarify that, for onshore production sites not subject to NSPS OOOOb or EG OOOOc that elect to conduct leak detection surveys, a complete leak detection survey must include all components at a single well-pad and associated with that single well-pad. Also after consideration of comments, for the natural gas distribution industry segment, we are finalizing new amendments to the use of Calculation Method 2 for facilities utilizing a multi-year survey cycle to specify the use of volumetric emissions, rather than mass emissions, resulting from this method to determine the meter/regulator run population emission factor in accordance with 40 CFR 98.233(q)(viii)(A). This change will simplify the process of using the measurement data to develop the population emission factor for facilities using a multi-year survey cycle. Additionally, we are also finalizing two corrections to cross-references in 40 CFR 98.233(q)(3) and the related “CountMR” and “Es,e,i” variables in 40 CFR 98.233(r) as a result of consideration of public comments and EPA review.
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to add a method to quantify emissions from equipment leak surveys using direct measurement.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters stated that there may be situations at a facility where direct measurement is not feasible or safe to conduct, thus meaning the survey that did not include measurements for these components would be considered incomplete and as a result facilities would not be able to use the direct measurement option. Commenters added that excluding components for which measurement is infeasible or unsafe should not prevent reporters from conducting direct measurement of equipment elsewhere on the facility. Commenters asserted that the EPA's proposal disincentivizes the use of direct measurement, the most accurate means of emission quantification. Commenters requested that the EPA allow reporters the option to use direct measurement and/or EFs as appropriate during a complete leak detection survey.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We understand and agree with commenters that there may be components that are difficult or unsafe to measure. We are finalizing provisions in 40 CFR 98.233(q)(3)(i) to provide for the use of substitute measurement data for components that require elevating the measurement personnel more than 2 meters above the surface and a lift is unavailable at the site or would pose immediate danger to measurement personnel performing the direct measurement using one of the methods in 40 CFR 98.234(a). These final provisions will allow facilities to substitute measurement data only for components meeting these criteria with the component-specific and service-specific default leak rate in final tables W-2, W-4, or W-6, as applicable. The use of substitute data will also ensure that a facility electing to use the direct measurement option can still successfully perform a complete leak detection survey as required by this option. The final amendments narrowly define when data substitutions can be used to ensure the accuracy of the estimate while accommodating feasibility and promoting safety.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters supported the option for facilities to calculate their emissions based on the results of direct measurement. Commenters noted that in order for natural gas distribution facilities to use the measurement option, facilities must perform a complete leak detection survey, which for natural gas distribution companies may take up to 5 years depending on the length of the survey cycle. Commenters then requested that natural gas distribution companies/utilities be allowed to continue using their previous T-D emission factors for any stations that have not yet been subject to direct measurements until such time as all of that LDC's stations have gone through one full cycle of surveying. Commenters stated that under this approach, once the full cycle of measuring all T-Ds has been completed, the previous emission factors would no longer be used.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         Under the existing subpart W provisions, natural gas distribution companies must survey their above grade transmission distribution transfer stations and may elect to do so over a single or multi-year survey cycle not to exceed five years. If leaks are detected at the above grade transmission distribution transfer stations during these surveys, the emissions are quantified using equation W-30 with the count of leaks, the default leaker emission factor, and the total time the surveyed component was assumed to be leaking and operational. The emissions from the above grade transmission distribution transfer stations are used with equation W-31 to develop a facility-level meter/regulator run population emission factor, which, depending on the length of the survey cycle, is applied to the count of meter/regulator runs at all above grade transmission distribution transfer stations and/or the count of meter/regulator runs at above grade metering-regulating stations. The facility-level meter/regulator run population emission factor must be calculated annually, which for facilities electing a multi-year survey cycle means the results of the current calendar year leak survey and the results from prior year leak surveys are included in the calculation of the meter/regulator run population emission factor on a rolling basis such that a full survey cycle of results is included.
                    </P>
                    <P>
                        Through this final rulemaking, natural gas distribution companies will now have the option to either continue to use the default leaker emission factors and equation W-30 to quantify equipment leak emissions from their above grade transmission distribution transfer stations or perform direct measurement of leaking components found during the equipment leak surveys conducted at their above grade transmission distribution transfer stations. The emissions from their above grade transmission distribution transfer stations—whether based on calculations using default leaker emission factors or direct measurements—must still be used with equation W-31 to develop a facility-level meter/regulator run population emission factor. The facility-level meter/regulator run population emission factor must still be applied to the count of meter/regulator runs at all above grade transmission distribution transfer stations and/or the count of meter/regulator runs at above grade metering-regulating stations, depending on the length of the survey cycle, to estimate emissions from these stations. The facility-level meter/regulator run population emission factor must still be updated annually. For the first few years following the effective date of the direct measurement option provided in this final rule, for facilities that elect to survey over a multi-year survey cycle and that elect to use the direct measurement option, the developed facility-level meter/regulator run population emission factor will be informed by emissions quantities at above grade transmission distribution transfer stations that were estimated using default leaker emission factors (
                        <E T="03">i.e,</E>
                         the existing method) and direct measurement (
                        <E T="03">i.e,</E>
                         the new method). For example, if a facility elects to survey all their stations over a 2-year survey cycle and for Year 1 they use the existing method (
                        <E T="03">i.e,</E>
                         equipment leak surveys of their above grade transmission distribution transfer stations, leaks 
                        <PRTPAGE P="42166"/>
                        quantified using the default leaker emission factors) and for Year 2 they use the new method (
                        <E T="03">i.e,</E>
                         equipment leak surveys of their above grade transmission distribution transfer stations, leaks quantified using direct measurement), the resulting facility-level meter/regulator run population emission factor will be informed by emissions calculated using the existing and new calculation methods. This is expected to be temporary and only be an issue for no more than five years (
                        <E T="03">i.e,</E>
                         the maximum survey cycle length) and only for the subset of facilities that elect a multi-year survey cycle and elect to use the direct measurement option.
                    </P>
                    <P>
                        Concerning the comment that natural gas distribution companies electing to survey over a multi-year survey cycle and electing to use the direct measurement option should be able to use their historical facility-level meter/regulator run population emission factors (
                        <E T="03">i.e,</E>
                         based on the existing method) until a survey cycle incorporating only direct measurement data has been completed, we find that natural gas distribution companies will obtain the necessary data by following the direct measurement method (
                        <E T="03">i.e,</E>
                         the volumetric emissions by component type) to combine with the volumetric emissions from historical surveys (
                        <E T="03">i.e,</E>
                         the volumetric emissions calculated according to equation W-30) for the prior year facility-level meter/regulator run population emission factor development to continue to estimate the facility-level meter/regulator run population emission factors in accordance with equation W-31. Therefore, we do not see a need to provide that historical facility-level meter/regulator run population emission factors can be used until such time that a complete survey cycle including only direct measurements of all stations has been completed. Consequently, as described above we acknowledge that for a limited period of time and limited number of facilities, this means that the facility-level meter/regulator run population emission factors may have a mix of emissions data calculated using the default leaker emission factors (
                        <E T="03">i.e,</E>
                         the existing calculation method) and direct measurements (
                        <E T="03">i.e,</E>
                         the new leaker measurement method).
                    </P>
                    <P>
                        In considering these comments, we performed a review of the proposed procedures for utilizing the leaker measurement method for natural gas distribution companies. We proposed in 40 CFR 98.233(q)(3)(viii)(A) that in order to determine the CO
                        <E T="52">2</E>
                         and CH
                        <E T="52">4</E>
                         facility-level meter/regulator run population emission factor using equation W-31, reporters were to use equation W-31 and the mass emissions calculated in accordance with 40 CFR 98.233(q)(3)(vi). During our review, we noted that the historical facility-level population emission factors have been calculated on a volumetric basis (
                        <E T="03">i.e,</E>
                         the resulting population emission factor from equation W-31 has units of measure of standard cubic feet of GHGi per operational hour of all meter/regulator runs) and the provisions for estimating emissions utilizing the facility-level meter/regulator run population emission factors in 40 CFR 98.233(r) requires a volumetric based emission factor. Therefore, we are finalizing amendments to 40 CFR 98.233(q)(3)(viii)(A) to instead require that for reporters electing to use the direct measurement option and using equation W-31 to develop their facility-level meter/regulator run population emission factor use the sum of the volumetric emissions at standard conditions by component type required to be surveyed calculated in accordance with 40 CFR 98.233(q)(3)(iv) rather than mass emissions as was proposed. This simplifies the use of the direct measurement data as it does not require conversion to mass emissions. This change also allows reporters electing to perform a multi-year survey cycle to more easily combine historical volumetric emission rates with direct measurements to develop their meter/regulator run population emission factors.
                    </P>
                    <HD SOURCE="HD3">4. Addition of a Method To Develop Site-Specific Component-Level Leaker Emission Factors</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        As noted in section III.P. of this preamble, facilities are currently required to perform leak surveys to determine the number of leaking components. The results of these surveys (
                        <E T="03">i.e.</E>
                        , the count of leakers) are used with default emission factors to estimate the quantity of resulting emissions. As noted in the previous section of this preamble, the EPA is finalizing as proposed an additional option for facilities to conduct leak surveys and perform direct measurement to quantify the emissions from equipment leak components.
                    </P>
                    <P>The EPA recognizes that while direct measurement is the most accurate method for determining equipment leak emissions, it may also be time consuming and costly. In consideration of both the advantages of and potential burdens associated with direct measurement, the EPA is also finalizing a method to use direct measurement from leak surveys to develop component level emission factors based on facility-specific leak measurement data. The facility-specific emission factors would provide increased accuracy over the use of default emission factors, consistent with section II.B. of this preamble, while lessening a portion of the burden of directly measuring every leak.</P>
                    <P>
                        We are finalizing as proposed that all facilities that elect to follow the direct measurement provisions in proposed 40 CFR 98.233(q)(3)(i) must track the individual measurements of natural gas flow rate by specific component type (valve, connector, 
                        <E T="03">etc.,</E>
                         as applicable for the industry segment) and leak detection method for the development of facility-specific component-level leaker emission factors. We are finalizing three different bins for the leak detection methods: Method 21 using a leak definition of 500 ppm as specified in 40 CFR 98.234(a)(2)(i); Method 21 using a leak definition of 10,000 ppm as specified in 40 CFR 98.234(a)(2)(ii); and OGI and other leak detection methods as specified in 40 CFR 98.234(a)(1), (3), or (5). We are finalizing as proposed that reporters must compile at least 50 individual measurements of natural gas flow rate for a specific component type and leak detection method (
                        <E T="03">e.g.,</E>
                         gas service valves detected by OGI) before they can develop and use the facility-specific emission factors for the component types at the facility. Based on consideration of comments received on the 2023 Subpart W Proposal, we are finalizing a change from proposal to the terminology of the emission factor from “site-specific” to “facility-specific” to better characterize the application of the developed emission factor, which is to be at the facility-level based on site-level measurement data for certain industry segments. We are finalizing as proposed that these flow rate measurements are required to be converted to standard conditions following the procedures in 40 CFR 98.233(t). We are also finalizing as proposed that the volumetric measurements comprised of at least 50 measured leakers must then be summed and divided by the total number of leak measurements for that component type and leak detection method combination. The resulting value will be an emission factor in units of standard cubic feet per hour-component (scf/hr-component). This facility-specific emission factor must be used, when available, to calculate equipment leak emissions following the procedures in 40 CFR 98.233(q)(2). Because some equipment component types are more prevalent 
                        <PRTPAGE P="42167"/>
                        and more likely to reach 50 leak measurements than other components, application of the calculation methodology in 40 CFR 98.233(q)(2) may include default leaker factors for some components and facility-specific leaker factors for other components.
                    </P>
                    <P>We are also finalizing as proposed in 40 CFR 98.236(q) to require that the emissions be reported at the aggregation of calculated or measured values for the combination of component type and leak detection method. As discussed in more detail in section III.P.1. of this preamble, numerous studies have shown that different leak detection methods identify different populations of leaking components; therefore, consistent with the delineation of the default emission factors by leak detection method, site-specific emission factors are delineated in the same way under the final provisions.</P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to add a method to develop a site-specific component-level leaker emission factor.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters noted that the EPA's intent to allow for site-level measurement data to be used to develop a representative facility-level emission factor was clear from the discussion in the preamble to the 2023 Subpart W Proposal, however the use of the term “site-specific” in 40 CFR 98.233(q)(3) may make this intent less clear. Therefore, commenters requested that the EPA clarify that only a facility-wide emission factor based on direct measurement at a representative sampling of well sites is needed.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We are clarifying in the final provisions that the site-specific emission factor approach in proposed 40 CFR 98.233(q)(4) provides for the development of an emission factor that is applied at the facility-level. For example, consistent with the description in the preamble to our proposed rule, for the purposes of subpart W, an onshore production facility may be comprised of multiple well sites. The survey and measurement of all subject equipment leak components using the methods in 40 CFR 98.234(a) at a well site constitutes a complete leak detection survey of that well site. The measurements obtained must be included in the component-specific datasets underlying the site-specific emission factor. Once sufficient measurements are made, the site-specific emission factor developed in accordance with proposed 40 CFR 98.233(q)(4) may be applied to equipment leak components at any of the well sites within the basin that comprise the onshore production subpart W facility. In order to make this clearer, the final terminology changes the name from the proposed “site-specific” to the final “facility-specific” emission factor.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters stated that the requirement to accumulate a minimum of 50 leak measurements for a given component and leak detection method combination was impractical and could take many years of surveys. Some commenters stated that the EPA has not justified why a minimum of 50 measurements is appropriate and reasonable. Some commenters added that the minimum number of measurements proposed may disincentivize measurement and penalize operators with a small number of sites. Other commenters recommended a tiered approach whereby the minimum number of leak measurements would be determined by the number of well sites or gathering and boosting sites comprising the GHGRP onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facility, respectively. Other commenters recommended the EPA allow the development of site-specific emission factors at the company level where owners/operators could combine measurements from multiple GHGRP facilities together to develop the emission factors. Some commenters also stated that the component and survey method specific default leaker emission factors developed using the combination of data from the Zimmerle 
                        <E T="03">et al.</E>
                         (2020) and Pacsi
                        <E T="03"> et al.</E>
                         (2019) studies did not meet the measurement minimum the EPA proposed for the development of site-specific emission factors.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We have considered the comments received on the minimum number of measurements (
                        <E T="03">i.e.</E>
                        , 50) required by component type and survey method combination to meet the criteria for development of a facility-specific emission factor as proposed in 40 CFR 98.233(q)(4). We have performed additional analysis of the reported leaker data to assess these comments. The details of these analyses are presented in the Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for Data Elements Under the Greenhouse Gas Reporting Rule; Final Rule—Petroleum and Natural Gas Systems, which is available in the docket for this rulemaking (Docket ID No. EPA-HQ-OAR-2023-0234). We generally find that this approach was provided to reduce the burden of measurement, while increasing the accuracy of the associated emission estimate over that of using a default leaker emission factor since it is based on sufficient facility-specific measurements to be considered statistically representative.
                    </P>
                    <P>
                        The first analysis we performed was to determine the average number of leakers by component type and industry segment per facility-year. We find that for components that are more commonly found in service (
                        <E T="03">e.g.</E>
                        , valves, connectors), a facility-specific emission factor could be developed in 5 years or less for facilities in the onshore production, gathering and boosting, underground storage and LNG import/export industry segments based on the historical count of leakers per facility-year. Conversely, we agree with commenters that for some industry segments (
                        <E T="03">e.g.</E>
                        , processing, transmission compression, LNG storage, NGD) and some types of components (
                        <E T="03">e.g.</E>
                        , OEL, Pump Seals), it may take many years to accumulate sufficient measurements to develop a facility-specific emission factor. For example, OEL and pump seals have very low (if any) reported leakers on average per facility-year for any of the 7 industry segments. In this case, reporters may decide that using this method for these components may not be reasonable. However, facilities would still be able to use the default emission factor for these components or continue to take their own measurements to ensure the accuracy of the reported data.
                    </P>
                    <P>
                        The provisions to directly measure and develop a facility-specific emission factor is one of several options to quantify emissions from equipment leaks. Regarding the comments to allow for the development of company specific emission factors, we note that the equipment leak provisions for direct measurement are based on measurements aggregated at a facility level. If we were to include an option for facilities to develop a company level emission factor, facilities with multiple GHGRP facilities may not have to measure every facility to develop a company level emission factor. We do not believe that extrapolating an emission factor based on a select subset of facilities across all facilities that are part of the corporate entity would be appropriate. Subpart W allows corporate emission factors for compressors because as found measurements are required for every compressor at all facilities in the corporate entity, ensuring representativeness. However, in this case measurements are not required at every facility (
                        <E T="03">i.e.</E>
                        , facilities can elect the leaker method, the direct 
                        <PRTPAGE P="42168"/>
                        measurement method or the population count method, as applicable) such that the company level emission factor may not be representative of all facilities. That is, owners may look to conduct measurements only at newer facilities or facilities that are otherwise expected to have lower emissions, and therefore potentially bias the corporate emission factor. Therefore, we are not providing an option for component level leaker emission factors to be developed at the company level and are maintaining our proposed facility-specific emission factor method.
                    </P>
                    <P>
                        The second analysis we performed was to utilize the combined Zimmerle 
                        <E T="03">et al.</E>
                         (2020) and Pacsi 
                        <E T="03">et al.</E>
                         (2019) dataset and the resulting proposed leaker emission factors to perform a statistical analysis. In this analysis, we sought to determine the impact of sample size on the EF for each component. For example, for leaking connectors detected with OGI at gas sites, the combined dataset of the Zimmerle 
                        <E T="03">et al.</E>
                         (2020) and Pacsi 
                        <E T="03">et al.</E>
                         (2019) studies contain 217 measurements for this component type. In this analysis, a range of sample sizes was simulated for each component. Each sample size was simulated 10,000 times by sampling the available data with replacement, meaning no data points were removed from the available data when developing the distribution and, thus, could be chosen again during the simulations. We then compared the distribution of the estimated emission factor against the number of samples in the simulations.
                    </P>
                    <P>Second, we are finalizing as proposed revisions to 40 CFR 98.234(a) to clarify and consolidate the requirements for OGI and Method 21 in 40 CFR 98.234(a)(1) and (2), respectively. In the 2016 amendments to subpart W (81 FR 4987, January 29, 2016), the EPA added 40 CFR 98.234(a)(6) and (7) to provide OGI and Method 21 as specified in NSPS OOOOa as leak detection survey methods. Specifically, the EPA is finalizing the amendments to move 40 CFR 98.234(a)(1) and 40 CFR 98.234(a)(6) to 40 CFR 98.234(a)(1)(i) and 40 CFR 98.234(a)(1)(ii), respectively, which will consolidate the OGI-based methods in 40 CFR 98.234(a)(1). Similarly, the EPA is finalizing revisions to 40 CFR 98.234(a)(2) such that 40 CFR 98.234(a)(2)(i) is Method 21 with a leak definition of 10,000 ppm and 40 CFR 98.234(a)(2)(ii) is Method 21 with a leak definition of 500 ppm. This final amendment will effectively move 40 CFR 98.234(a)(7) to 40 CFR 98.234(a)(2)(ii). We are also finalizing that the references to “components listed in § 98.232” will be replaced with a more specific reference to 40 CFR 98.233(q)(1). The references to specific provisions in 40 CFR 60.5397a in 40 CFR 98.234(a)(6) and (7) will be moved to 40 CFR 98.234(a)(1)(ii) and 40 CFR 98.234(a)(2), as applicable.</P>
                    <P>In March 2024, the EPA finalized in NSPS OOOOb and EG OOOOc that owners and operators of natural gas processing facilities will detect leaks using an OGI-based monitoring method following the final appendix K to 40 CFR part 60 (89 FR 16820). We are finalizing as proposed amendments to include that same method in subpart W at 40 CFR 98.234(a)(1)(iii) to ensure that reporters of those facilities will be able to comply with the subpart W requirement to use data derived from the NSPS OOOOb or 40 CFR part 62 fugitive emissions requirements for purposes of calculating emissions from equipment leaks. In addition, as part of the final NSPS OOOOb and EG OOOOc, the EPA finalized an alternative periodic screening approach for fugitive emissions from well sites, centralized production facilities and compressor stations under 40 CFR 60.5398b(b) that will allow the use of advanced technologies approved under 40 CFR 60.5398b(d) to detect large equipment leaks. Under the NSPS OOOOb and EG OOOOc final rule, if emissions are detected using an approved advanced technology, facilities will be required to conduct monitoring using OGI or Method 21 to identify and repair specific leaking equipment. Additionally, under the NSPS OOOOb and EG OOOOc final rule, even if no emissions are identified during a periodic screening survey, some facilities using these advanced technologies will still be required to conduct annual fugitive emissions monitoring using OGI. The EPA's intent in this final rule for subpart W is that the results of those NSPS OOOOb and 40 CFR part 62 OGI or Method 21 surveys will be used for purposes of calculating emissions for subpart W, as OGI and Method 21 are capable of identifying leaks from individual components and they are included in the leak detection methods provided in subpart W. Thus, after further consideration, including consideration of comments we received on the 2023 Subpart W Proposal, we are finalizing new amendments that will require the reporting of fugitive emissions monitoring survey results conducted to comply with the alternative periodic screening approach in the NSPS OOOOb, including annual affected facility-level OGI surveys pursuant to 40 CFR 60.5398b(b)(4) and affected facility-level ground based monitoring surveys pursuant to 40 CFR 60.5398b(b)(5)(ii).</P>
                    <P>
                        Third, we are finalizing as proposed subpart W requirements for onshore natural gas processing facilities consistent with certain requirements for equipment leaks in the final NSPS OOOOb or EG OOOOc. Currently, onshore natural gas processing facilities 
                        <PRTPAGE P="42170"/>
                        must conduct at least one complete survey of all the components listed in 40 CFR 98.232(d)(7) each year, and each complete survey must be considered when calculating emissions according to 40 CFR 98.233(q)(2). Under the equipment leak detection and repair program included in the final NSPS OOOOb and the EG OOOOc presumptive standards, owners and operators must conduct bimonthly (
                        <E T="03">i.e.</E>
                        , once every other month) OGI monitoring in accordance with 40 CFR part 60, appendix K to detect equipment leaks from pumps in light liquid service, pressure relief devices in gas/vapor service, valves in gas/vapor or light liquid service, connectors in gas/vapor or light liquid service, and closed vent systems in accordance with 40 CFR 60.5400b and 60.5400c, respectively. As an alternative to the bimonthly OGI monitoring, EPA Method 21 may be used to detect leaks from the same equipment at frequencies specific to the process unit equipment type (
                        <E T="03">e.g.</E>
                        , monthly for pumps, quarterly for valves) in accordance with 40 CFR 60.5401b and 60.5401c, respectively. Open-ended valves and lines, pumps, valves and connectors in heavy liquid service and pressure relief devices in light liquid or heavy liquid service must be monitored using AVO. For the alternative approach provided in NSPS OOOOb and EG OOOOc using EPA Method 21, different component types may be monitored on different frequencies, so all equipment at the facility is not always monitored at the same time. According to the current requirements in 40 CFR 98.233(q), surveys that do not include all of the applicable equipment at the facility are not considered complete surveys and are not used for purposes of calculating emissions. Therefore, we are finalizing in 40 CFR 98.233(q)(1)(vii)(F) that onshore natural gas processing facilities subject to NSPS OOOOb or an applicable approved state plan or the applicable Federal plan in 40 CFR part 62 must use the data derived from each equipment leak survey conducted as required by NSPS OOOOb or the relevant subpart of 40 CFR part 62 along with the subpart W equipment leak survey calculation methodology and leaker emission factors to calculate and report GHG emissions to the GHGRP, even if a survey required for compliance with NSPS OOOOb or 40 CFR part 62 does not include all the component types listed in 40 CFR 98.232(d)(7). Under this final amendment, onshore natural gas processing facility reporters will still have to meet the subpart W requirement to conduct at least one complete survey of all applicable equipment at the facility per year, so if there were components listed in 40 CFR 98.232(d)(7) not included in any NSPS OOOOb or 40 CFR part 62-required surveys conducted during the year, reporters subject to NSPS OOOOb or 40 CFR part 62 will need to either add those components to one of their required surveys, making that a complete survey for purposes of subpart W, or conduct a separate complete survey for purposes of subpart W.
                    </P>
                    <P>
                        We are also finalizing as proposed to add leaker emission factors for all survey methods for “other” components that would be required to be monitored under NSPS OOOOb or an approved state plan or applicable Federal plan in 40 CFR part 62 or that reporters elect to survey that are not currently included in subpart W. These final THC leaker emission factors for the “other” component type are of the same value as the THC leaker emission factors for the “other” component type for the Onshore Natural Gas Transmission Compression and the Underground Natural Gas Storage industry segments (existing table W-3A and table W-4A to subpart W, respectively, final table W-4 to subpart W). For more information on the derivation of the original emission factors, see the 2010 subpart W TSD,
                        <SU>69</SU>
                        <FTREF/>
                         and for more information on the derivation of the “other” component type emission factor proposed to be applied to these types of leaks at facilities in the Onshore Natural Gas Processing industry segment, see the TSD for the 2016 amendments to subpart W.
                        <SU>70</SU>
                        <FTREF/>
                         In a corresponding amendment, we are also finalizing as proposed the expansion of the reporting requirement in existing 40 CFR 98.236(q)(1)(iii) (finalized 40 CFR 98.236(q)(1)(iv)) to require onshore natural gas processing reporters to indicate if any of the surveys used in calculating emissions under 40 CFR 98.233(q) were conducted to comply with the equipment leak standards in NSPS OOOOb or an applicable approved state plan or the applicable Federal plan in 40 CFR part 62.
                    </P>
                    <FTNT>
                        <P>
                            <SU>69</SU>
                             
                            <E T="03">Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Systems Industry: Background Technical Support.</E>
                             November 2010. Docket ID. No. EPA-HQ-OAR-2009-0923-3610; also available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>70</SU>
                             
                            <E T="03">Greenhouse Gas Reporting Rule: Technical Support for Leak Detection Methodology Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems.</E>
                             November 1, 2016. Docket ID. No. EPA-HQ-OAR-2015-0764-0066; also available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        After consideration of comments received on the 2023 Subpart W Proposal, we are finalizing new amendments to cross reference the alternative standards (
                        <E T="03">i.e.,</E>
                         use of EPA Method 21), in addition to the emission standard (
                        <E T="03">i.e.,</E>
                         bimonthly OGI surveys), for fugitive emission sources in NSPS OOOOb for natural gas processing plants to ensure that all surveys conducted for the NSPS OOOOb are included in subpart W. Additionally, in response to comments on the 2023 Subpart W Proposal, we are codifying a regulatory cross refence that provides an exemption to survey equipment leak components that are considered “inaccessible” for natural gas processing plants in 40 CFR 98.233(q)(vii)(F). This exemption only applies to components that are “inaccessible” as provided in 40 CFR 60.5401b(h)(3) and 60.5401c(h)(3) for facilities using the EPA Method 21 leak survey method. In the existing subpart W rule, the term “inaccessible” is used in 40 CFR 98.234(a)(1), (2), (6) and (7) to refer to equipment leak components that require monitoring personnel to be elevated more than 2 meters off the surface. As stated in the existing rule text, these components are not exempt from monitoring rather they must be monitored using OGI if EPA Method 21 cannot be used to monitor the inaccessible equipment leaks. During rearrangement of the rule text in the 2023 Subpart W Proposal, this language was proposed to be moved and consolidated at 40 CFR 98.234(a). In the NSPS OOOOb and EG OOOOc, the term “difficult-to-monitor” is used to characterize components that require monitoring personnel to be elevated more than 2 meters off the surface. In response to comments and in order to be consistent with the terminology in the NSPS OOOOb and EG OOOOc, we are revising the term in the final rule from “inaccessible” to “difficult-to-monitor” in 40 CFR 98.234(a). We are also making the same revision to change the term “inaccessible” to “difficult-to-monitor” in 40 CFR 98.233(q)(1)(vii)(F) of the final rule for consistency in the use of the term.
                    </P>
                    <P>
                        Finally, in our review of subpart W equipment leak requirements for onshore natural gas processing facilities, we found that the leak definition for the Method 21-based requirements for processing plants in NSPS OOOOa (as well as final NSPS OOOOb and EG OOOOc presumptive standards) is not consistent with the leak definition in the Method 21 option in the current 40 CFR 98.234(a)(2), which is the only Method 21-based method available to onshore natural gas processing facilities under subpart W. Based on this review, and to complement the final addition of 
                        <PRTPAGE P="42171"/>
                        default leaker emission factors for survey methods other than Method 21 (as described previously in this preamble), we are finalizing as proposed several additions to the equipment leak survey requirements for the Onshore Natural Gas Processing industry segment, beyond those amendments already described related to the final NSPS OOOOb and EG OOOOc presumptive standards. First, we are finalizing default leaker emission factors for Method 21 at a leak definition of 500 ppm in final table W-4 to subpart W. As with the final “other” component type leaker emission factors, these final leaker emission factors (
                        <E T="03">i.e.,</E>
                         valve, connector, open-ended line, pressure relief valve and meter) are of the same value as the THC leaker emission factors for the Onshore Natural Gas Transmission Compression and the Underground Natural Gas Storage industry segments (existing table W-3A and table W-4A, respectively). For more information on the derivation of those emission factors, see the TSD for the 2016 amendments to subpart W.
                        <SU>71</SU>
                        <FTREF/>
                         In addition, we are finalizing to add 40 CFR 98.233(q)(1)(v) to indicate that onshore natural gas processing facilities not subject to NSPS OOOOb or an approved state plan or the applicable Federal plan in 40 CFR part 62 may use any method specified in 40 CFR 98.234(a), including Method 21 with a leak definition of 500 ppm and OGI following the provisions of appendix K to 40 CFR part 60. This final amendment will ensure that equipment leak surveys conducted using any of the approved methods in subpart W would be available for purposes of calculating emissions, not just those surveys conducted using one of the methods currently provided in 40 CFR 98.234(a)(1) through (5).
                    </P>
                    <FTNT>
                        <P>
                            <SU>71</SU>
                             
                            <E T="03">Greenhouse Gas Reporting Rule: Technical Support for Leak Detection Methodology Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems.</E>
                             November 1, 2016. Docket ID. No. EPA-HQ-OAR-2015-0764-0066; also available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters expressed support for allowing the results of monitoring surveys conducted in accordance with the NSPS OOOOb and 40 CFR part 62 state plans. Commenters stated that the EPA should, however, allow the use of the results of all monitoring surveys conducted for the NSPS OOOOb and 40 CFR part 62 state plans for reporting, including follow-up surveys.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We are finalizing, with some changes consistent with the proposal to reflect the NSPS OOOOb and EG OOOOc final rules, that the results of monitoring surveys for fugitive emissions components affected facilities conducted under the NSPS OOOOb and EG OOOOc will be required to be reported to subpart W.
                    </P>
                    <P>
                        NSPS OOOOb and EG OOOOc in 40 CFR 60.5397b and 60.5397c, respectively, provide the emission standards for fugitive emissions components affected and designated facilities, which include initial and subsequent monitoring surveys using AVO, OGI or Method 21 with a leak definition of 500 ppm depending on site type (
                        <E T="03">e.g.,</E>
                         single wellhead only well sites, multi-wellhead only well sites).
                    </P>
                    <P>
                        We are finalizing, as proposed, the provisions that facilities must report the results of equipment leak surveys conducted to comply with 40 CFR 60.5397b and 60.5397c of the NSPS OOOOb and EG OOOOc, respectively, as long as they were conducted using one of the leak survey methods included in subpart W at 40 CFR 98.234(a) (
                        <E T="03">i.e.,</E>
                         OGI or Method 21) and constitute a complete leak survey as specified in 40 CFR 98.233(q)(1)(vii).
                    </P>
                    <P>40 CFR 60.5398b(b) and 60.5398c(b) of the NSPS OOOOb and EG OOOOc, respectively, provide the option to demonstrate compliance with the alternative standards for fugitive emissions components affected and designated facilities using periodic screening. Under those provisions, the periodic screening can be performed using advanced technologies that are approved under 40 CFR 60.5398b(d). Under those provisions, the frequency of periodic screening is determined based on the minimum aggregate detection threshold of the method used to conduct the periodic screenings and site type. Some NSPS OOOOb affected facilities and EG OOOOc designated facilities are required to perform an affected facility-level OGI survey independent of the results of the periodic screening, including the following:</P>
                    <P>• Well sites and centralized production facilities that contain certain major production and processing equipment, and compressor stations: Bimonthly Screening and ≤10 kg/hr technology detection threshold;</P>
                    <P>• Well sites or centralized production facilities that contain certain major production and processing equipment, and compressor stations: Monthly Screening and ≤15 kg/hr technology detection threshold;</P>
                    <P>• Single wellhead only well sites, small well sites, and multi-wellhead only well sites: Triannual and ≤10 kg/hr technology detection threshold; and</P>
                    <P>• Single wellhead only well sites, small well sites, and multi-wellhead only well sites: Quarterly Screening and ≤15 kg/hr technology detection threshold.</P>
                    <P>Additionally, under those provisions any periodic screening result with a confirmed detection of emissions found with the approved advanced technology requires a ground-level follow-up survey using OGI or Method 21 with a leak definition of 500 ppm. Depending on the spatial resolution of the approved advanced technology, the follow-up monitoring survey is required at the affected facility level, area-level or component-level. In order to ensure that monitoring surveys conducted in accordance with 40 CFR 60.5398b(b) and 60.5398c(b) of the NSPS OOOOb and EG OOOOc, respectively, which constitute a complete leak detection survey and were conducted using one of the methods in 40 CFR 98.234(a) are also required to be reported to subpart W, we are adding provisions to include these survey results in the final rule. These provisions specifically include the annual OGI surveys required in 40 CFR 60.5398b(b)(4) and 60.5398c(b)(4) as well as the facility-level follow-up monitoring surveys conducted in accordance with 40 CFR 60.5398b(b)(5)(ii) or 60.5398c(b)(5)(ii). The area or component-level monitoring surveys conducted in accordance with 40 CFR 60.5398b(b) and 60.5398c(b) of the NSPS OOOOb and EG OOOOc, respectively, are not considered complete leak detection surveys for purposes of subpart W reporting because the surveys only cover a subset of equipment leak components at each site. The partiality of these area or component-level surveys may not provide representative emissions coverage of each well-pad site or gathering and boosting site. Therefore, we are not allowing inclusion of the NSPS OOOOb and EG OOOOc area or component-level monitoring survey results in the final rule requirements for subpart W. However, we note that reporters may elect to conduct site-level surveys while on site to conduct NSPS OOOOb and EG OOOOc area or component-level surveys, and reporting and use the results of these site-level surveys would then be included in the final rule requirements for reporting under subpart W in accordance with the provisions of 98.233(q)(1)(vii)(D) and (E).</P>
                    <P>
                        <E T="03">Comment:</E>
                         For natural gas processing facilities, commenters recommended that references to 40 CFR 60.5400b should also include a reference to the 
                        <PRTPAGE P="42172"/>
                        alternate equipment leak standards in 40 CFR 60.5401b to clarify that both OGI surveys conducted according to Appendix K and Method 21 surveys with a 500 ppmv leak definition should be used in emission calculations. Additionally, specifically for natural gas processing facilities, commenters stated that the inaccessible component exemption in 40 CFR 98.234(a) should be retained under Subpart W. Commenters stated that, for onshore gas processing, the term “Inaccessible” has a long-standing meaning under NSPS, which historically is limited to connectors that are monitored using Method 21 with specific criteria that extends well beyond the 2-meter clause noted in 40 CFR 98.234(a). Commenters stated that this exemption is directly linked to the safety of personnel or the technical use of monitoring equipment. Commenters stated that, specifically, connectors that are “buried” or that are “not able to be accessed at any time in a safe manner to perform monitoring (Unsafe access includes, but is not limited to, the use of a wheeled scissor-lift on unstable or uneven terrain, the use of a motorized man-lift basket in areas where an ignition potential exists, or access would require near proximity to hazards such as electrical lines or would risk damage to equipment)” should not require additional leak detection provisions under subpart W.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         Concerning the comment about cross-referencing the NSPS OOOOb alternative standard for natural gas processing plants, we updated the cross references in the subpart W final rule to the NSPS OOOOb to include 40 CFR 60.5401b for natural gas processing in 40 CFR 98.232(d)(7), 98.233(q)(1)(v), 98.233(q)(1)(vii)(F), and 98.236(q)(1)(iv)(D). These revisions add clarity to the subpart W equipment leak provisions.
                    </P>
                    <P>Concerning the comments on the inaccessible component exemption, we note that this language is not new, it was moved from 40 CFR 98.234(a)(2) to proposed 40 CFR 98.234(a) during reorganization of the rule at proposal. Additionally, as described in the preamble to our 2023 proposed rule, our intent is to align requirements between subpart W and the NSPS OOOOb and EG OOOOc, as appropriate. As noted by the commenter, the term “inaccessible” in the NSPS OOOOb and the EG OOOOc is limited to connectors and the term is only found in the context of complying with the alternative standard in 40 CFR 60.5401b(h)(3) and 60.5401c(h)(3), respectively. The NSPS OOOOb and EG OOOOc provide an exemption from the monitoring, leak repair, recordkeeping and reporting requirements for “inaccessible” connectors. Consistent with this exemption in the NSPS OOOOb and EG OOOOc, we are providing the same exemption for “inaccessible” components in 40 CFR 98.233(q)(1)(vii)(F) for onshore natural gas processing facilities. The term “difficult-to-monitor,” however, is included in the NSPS OOOOb and EG OOOOc specifically when using EPA Method 21 screening method and is characterized in the NSPS OOOOb and EG OOOOc as being for components that would require elevating the monitoring personnel more than 2 meters above a support surface. Therefore, we agree with commenters that we intended the term “inaccessible” to have the same meaning as the term “difficult-to-monitor” as provided in the NSPS OOOOb and EG OOOOc and we are therefore replacing the term “inaccessible” with the term “difficult-to-monitor” in 40 CFR 98.233(q)(1)(vii)(F) and 98.234(a).</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters encouraged the EPA to promote the use of alternative technologies for leak detection. Several commenters stated that the EPA should allow the use of technologies approved under the NSPS OOOOb and 40 CFR part 62 state plans advanced technology framework for quantification of equipment leak emissions under subpart W and/or develop a subpart W-specific framework for approval of alternate technologies for equipment leak emissions quantification.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA acknowledges comments requesting that the Agency promote the use of alternative technologies to detect leaks. The EPA is doing so to the extent it is appropriate in the context of subpart W in certain aspects of this final rulemaking. The EPA is aware of various technologies including fixed sensor monitors, UAVs or drones, aircraft, and satellites currently in use and deployed for various oil and gas survey purposes, as well as those in development. The EPA does not dispute the availability and capabilities of these newer developing technologies as alternative and supplements to standard leak detection technologies. However, as the commenters also indicate, there are several ongoing remote sensing activities to improve the understanding of how such advanced detection technologies work, and there is still much to learn on how data from remote sensing can be applied for emissions quantification. As discussed in the preamble to the final rule, we are not finalizing a framework for the adoption of advanced survey or measurement methane technology analogous to the performance-based technology approval process included in the NSPS OOOOb at 40 CFR 60.5398b(d).
                    </P>
                    <P>Under the “Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification or Reconstruction Commenced After December 6, 2022,” published on March 8, 2024 (89 FR 16820), the EPA finalized provisions to allow entities seeking to utilize the alternative compliance options under 40 CFR 60.5398b(b) (periodic screening alternative) and 60.5398b(c) (continuous monitoring alternative), in lieu of complying with the fugitive emissions standards under 40 CFR 60.5397b. In order to use the alternative compliance options of 40 CFR 60.5398b(b) and (c), entities must meet certain qualifications and must use advanced methane detection technology that has been approved by the EPA. In the final NSPS OOOOb at 40 CFR 60.5398b(d), the EPA provided specific detailed provisions that entities seeking to use technologies other than AVO, OGI and Method 21 must provide to the Agency in order to apply for specific alternative test method approval.</P>
                    <P>The final alternative test method provisions under NSPS OOOOb were specifically developed for the use of the advanced methane detection technology in lieu of the required fugitive emissions monitoring methods in the rule, and implements specific criteria for the review, evaluation, and potential use of advanced methane detection technology specifically for use in periodic screening, continuous monitoring, and/or super-emitter detection. The adoption of an alternative technology pathway under final NSPS for the oil and natural gas sector was primarily aimed at detecting fugitive emissions from well sites, centralized production facilities and compressor stations and to repair those confirmed detections as quickly as possible. Agency approved alternative technologies would be permitted to be used under NSPS OOOOb and EG OOOOc to find and identify leaks and repair confirmed detected sources of emissions.</P>
                    <P>
                        As described above, the focus of NSPS OOOOb and EG OOOOc is to find and repair leaks as quickly as possible in order to minimize emissions, and there is no requirement to quantify emissions. The EPA lacks specific information at this time in order to establish an alternative technology framework for subpart W analogous to that finalized for the NSPS OOOOb for fugitive emissions that the Agency believes would be appropriate to quantify and report emissions under subpart W. In 
                        <PRTPAGE P="42173"/>
                        order to quantify emissions from leaks identified using one of the alternative periodic screening approaches in the finalized NSPS OOOOb, we would need to have data collected using these screening methods compared to data collected with OGI or EPA Method 21 (or other appropriate data to quantitatively assess how the detected and quantified emissions compare to total actual emissions from equipment leaks) in order to develop appropriate leaker factors. As discussed in the preamble in section III.P.1. of this preamble, different screening approaches for leak detection result in the identification of different subsets of total leaks at a facility, due to the limitations of each screening approach. In order to develop accurate leaker factors or allow direct quantification of leak emission rates, the EPA would need data to understand the population of both detected and undetected leaks specific to the screening approach and associated detection limit.
                    </P>
                    <P>For these reasons and based on the additional discussion on this topic in section II.B. of this preamble, the EPA believes that a notice-and-comment rulemaking would be necessary to properly and adequately consider the adoption of the alternative technology framework in NSPS OOOOb that would be applicable and appropriate for subpart W purposes. In advance of such a rulemaking, the EPA intends to solicit input on the use of advanced measurement data and methods in subpart W through a white paper, workshop or request for information.</P>
                    <HD SOURCE="HD3">7. Exemption for Components in Vacuum Service</HD>
                    <P>
                        Through correspondence with the EPA via e-GGRT, some reporters have stated that certain equipment leak components at their facility are in vacuum service. These reporters indicated that there are no fugitive emissions expected from components in vacuum service. After consideration of these comments and in order to be consistent with other EPA equipment leak regulatory programs (
                        <E T="03">e.g.,</E>
                         40 CFR part 60, subpart VVa), we have determined that we agree with commenters. For these reasons, we are finalizing as proposed an exemption in the introductory paragraphs of 40 CFR 98.233(q) and (r) for leak components in vacuum service from the requirement to estimate and report emissions from these components. We are also finalizing as proposed a definition in 40 CFR 98.238 for the term “in vacuum service.” We are finalizing as proposed to require the reporting of the count of equipment in vacuum service to enable verification of the reported data (
                        <E T="03">i.e.,</E>
                         ability to confirm that all equipment for which emissions are expected has been accounted for and an indication that other equipment has been confirmed to meet the proposed definition of “in vacuum service”). The EPA received only supportive comments regarding these amendments. See the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
                    </P>
                    <HD SOURCE="HD2">Q. Equipment Leaks by Population Count</HD>
                    <P>
                        As noted in section III.P. of this preamble, subpart W reporters are currently required to quantify emissions from equipment leaks using the calculation methods in 40 CFR 98.233(q) (equipment leak surveys) and/or 40 CFR 98.233(r) (equipment leaks by population count), depending upon the industry segment. The equipment leaks by population count method uses the count of equipment components, subpart W emission factors (
                        <E T="03">e.g.,</E>
                         existing table W-1A to subpart W for the Onshore Petroleum and Natural Gas Production industry segment), and operating time to estimate emissions from equipment leaks. For the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments, the count of equipment components currently may be determined by counting each component individually for each facility (Component Count Method 2) or the count of equipment components may be estimated using the count of major equipment and subpart W default average component counts for major equipment (Component Count Method 1) in existing tables W-1B and W-1C, as applicable. Reporters in other industry segments currently must count each applicable component at the facility.
                    </P>
                    <P>We are finalizing, as proposed, several amendments to the calculation methodology provisions of 40 CFR 98.233(r) and the reporting requirements in 40 CFR 98.236(r) to improve the quality of the data collected, consistent with sections II.B. and II.C. of this preamble. Consistent with the 2023 Subpart W Proposal, the key changes included in this final rule are providing updated population count emission factors based on recent peer reviewed studies for: major equipment at Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting facilities; below grade stations, pipeline mains, and pipeline services at natural gas distribution facilities; and gathering pipelines at Onshore Petroleum and Natural Gas Gathering and Boosting facilities.</P>
                    <HD SOURCE="HD3">1. Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting Population Count Method</HD>
                    <P>
                        The EPA is finalizing several revisions related to equipment leaks by population count for equipment at onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities as described in this section. The EPA received only minor comments regarding these revisions. See the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
                    </P>
                    <P>
                        The existing population emission factors for the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments are found in existing table W-1A to subpart W. The gas service population emission factors are based on the 1996 GRI/EPA study 
                        <E T="03">Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks</E>
                         (available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234). The oil service population emission factors are based on the API's Emission Factors for Oil and Gas Production Operations, Publication 4615, published in 1995.
                    </P>
                    <P>
                        As noted previously in this section, when estimating emissions using the population count method, onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities currently under the existing provisions have the option to use actual component counts (
                        <E T="03">i.e.,</E>
                         Component Count Method 2) or to estimate their component counts using the count of major equipment (
                        <E T="03">e.g.,</E>
                         wellhead) and default component counts per major equipment (
                        <E T="03">e.g.,</E>
                         valves per wellhead) included in existing tables W-1B and W-1C of subpart W (
                        <E T="03">i.e.,</E>
                         Component Count Method 1). In reviewing subpart W data, we find that the vast majority (greater than 95 percent) of onshore production and natural gas gathering and boosting facilities use Component 
                        <PRTPAGE P="42174"/>
                        Count Method 1 to estimate the count of components.
                    </P>
                    <P>In the years that have followed the adoption of these emission factors into subpart W, there have been numerous studies regarding emissions from equipment leaks at onshore production and gathering and boosting facilities. Based on our review of these studies, our assessment is that they support revision of the population count method and corresponding emission factors for onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities, and we are finalizing as proposed amendments to this population count method and corresponding emission factors after consideration of these more recent study data, consistent with section II.B. of this preamble. These final amendments include new population emission factors that are on a per major equipment basis rather than a per component basis. As mentioned previously, the vast majority of reporters estimate the component counts using Component Count Method 1. By providing emission factors on a major equipment basis instead of by component, we will eliminate the step to estimate the number of components. All facilities will be able to count the actual number of major equipment and consistently apply the same emission factor to calculate emissions. This will reduce reporter burden and reduce the number of errors in the calculation of emissions, as we find that numerous facilities incorrectly estimate the number of components using Component Count Method 1 while providing consistently estimated emission results.</P>
                    <P>
                        In comparing the recent study data for the 2023 Subpart W proposal and this final rule, we concluded that the Rutherford 
                        <E T="03">et al.</E>
                         (2021) study represents the most robust sample size of approximately 3,700 measurements for developing population emission factors by major equipment. The larger sample size is likely more representative of varying degrees of leak detection and repair programs (
                        <E T="03">i.e.,</E>
                         not only facilities conducting frequent surveys), which can impact the number of leaks found during surveys (
                        <E T="03">i.e.,</E>
                         if more frequent surveys are being conducted and leaks are being repaired in a timely manner, then each survey likely finds less leaks). The Rutherford 
                        <E T="03">et al.</E>
                         (2021) study also employs a bootstrap resampling statistical approach 
                        <SU>72</SU>
                        <FTREF/>
                         that allows for the inclusion of infrequent large equipment leaks in the development of the emission factors, improving the representation of the inherent variability of equipment leaks in the developed emission factors. Therefore, we are finalizing as proposed major equipment emission factors developed using Rutherford 
                        <E T="03">et al.</E>
                         (2021) to provide population emission factors by major equipment and site type (
                        <E T="03">i.e.,</E>
                         natural gas system or petroleum system). The final emission factors were taken from Supplementary Tables 3 and 4 of Rutherford 
                        <E T="03">et al.</E>
                         (2021). The average emission factors presented in these study tables were converted from units of kilograms per day to standard cubic feet of whole gas per hour for cumulative equipment component leaks from different types of major equipment including wellheads, separators, heaters, meters including headers, compressors, dehydrators and tanks. The major equipment indicating venting emissions (
                        <E T="03">e.g.,</E>
                         tanks—unintentional vents) or emissions from other sources also covered by subpart W (
                        <E T="03">e.g.,</E>
                         liquids unloading, flaring, pumps) are not included in the final equipment leak population emission factors. Consistent with current requirements related to meters/piping at existing 40 CFR 98.233(r)(2)(i)(A), we are finalizing in 40 CFR 98.233(r)(2) that one meters/piping equipment should be included per well-pad for onshore petroleum and natural gas production operations and the count of meters in the facility should be used for this equipment category at onshore petroleum and natural gas gathering and boosting facilities. As a consequence of the broader scope of equipment surveyed in the study data that inform Rutherford 
                        <E T="03">et al.</E>
                         (2021), the final emission factors in final table W-1 to subpart W include more pieces of major equipment than are currently included in table W-1B and W-1C to subpart W. A complete description of the derivation of the final emission factors is discussed in more detail in the subpart W TSD, available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234. The final major equipment emission factors will replace the current component-based emission factors in the existing table W-1A. We are also finalizing removal, as proposed, of tables W-1B, W-1C, and W-1D since they will no longer be needed for the population count method for these industry segments. We are finalizing amendments, as proposed, to the reporting requirements for the use of the population count method to align with the reporting of major equipment counts consistent with the final emission factors in 40 CFR 98.236(r).
                    </P>
                    <FTNT>
                        <P>
                            <SU>72</SU>
                             Bootstrapping is a type of resampling where a known dataset is repeatedly drawn from, with replacement, to generate a sample distribution.
                        </P>
                    </FTNT>
                    <HD SOURCE="HD3">2. Natural Gas Distribution Emission Factors</HD>
                    <P>
                        The EPA is finalizing several revisions related to equipment leaks by population count for equipment at natural gas distribution facilities as described in this section. The EPA received only minor comments regarding these revisions. See the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
                    </P>
                    <P>
                        Natural gas distribution companies currently under the existing provisions quantify the emissions from equipment leaks from pipeline mains and services, below grade transmission distribution transfer stations, and below grade metering-regulating stations following the procedures in 40 CFR 98.233(r). This method uses the count of equipment, subpart W population emission factors in existing table W-7 (final table W-5) to subpart W, and operating time to estimate emissions. The population emission factors for distribution mains and services in existing table W-7 (final table W-5) are based on information from the 1996 GRI/EPA study.
                        <SU>73</SU>
                        <FTREF/>
                         Specifically for plastic mains, additional data are sourced from a 2005 ICF analysis.
                        <SU>74</SU>
                        <FTREF/>
                         The population emission factors for distribution mains are published per mile of main by pipeline material and emission factors for distribution services are published per service by pipeline material. The population emission factors for below grade stations in existing table W-7 (final table W-5) are based on information from the 1996 GRI/EPA study.
                        <SU>75</SU>
                        <FTREF/>
                         The population emission 
                        <PRTPAGE P="42175"/>
                        factors for below grade transmission-distribution transfer stations and below grade metering-regulating stations are currently specified in the existing table W-7 per station by three inlet pressure categories (&gt;300 pounds per square inch gauge (psig), 100-300 psig, &lt;100 psig).
                    </P>
                    <FTNT>
                        <P>
                            <SU>73</SU>
                             GRI/EPA. 
                            <E T="03">Methane Emissions from the Natural Gas Industry, Volume 9: Underground Pipelines.</E>
                             Prepared for Gas Research Institute and U.S. Environmental Protection Agency National Risk Management Research Laboratory by L.M. Campbell, M.V. Campbell, and D.L. Epperson, Radian International LLC. GRI-94/0257.2b, EPA-600/R-96-080i. June 1996. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>74</SU>
                             ICF. 
                            <E T="03">Fugitive Emissions from Plastic Pipe,</E>
                             Memorandum from H. Mallya and Z. Schaffer, ICF Consulting to L. Hanle and E. Scheehle, EPA. June 30, 2005. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>75</SU>
                             GRI/EPA. 
                            <E T="03">Methane Emissions from the Natural Gas Industry, Volume 10: Metering and Pressure Regulating Stations in Natural Gas Transmission and Distribution.</E>
                             Prepared for Gas Research 
                            <PRTPAGE/>
                            Institute and U.S. Environmental Protection Agency National Risk Management Research Laboratory by L.M. Campbell and B.E. Stapper, Radian International LLC. GRI-94/0257.27, EPA-600/R-96-080j. June 1996. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        In this rulemaking, the EPA is finalizing as proposed to update the population emission factors in existing table W-7 (final table W-5) to subpart W using the results of studies and information that were not available when the rule was finalized in 2010. Notably, the EPA reviewed recent studies and updated the emission factors for several natural gas distribution sources, including pipeline mains and services and below grade stations, for the 2016 U.S. GHG Inventory.
                        <SU>76</SU>
                        <FTREF/>
                         The majority of the U.S. GHG Inventory updates were based on data published by Lamb 
                        <E T="03">et al.</E>
                         in 2015.
                        <SU>77</SU>
                        <FTREF/>
                         Since the time that the 2016 U.S. GHG Inventory updates were made, additional studies for pipeline distribution mains have been published and reviewed by the EPA including Weller 
                        <E T="03">et al.</E>
                         in 2020.
                        <SU>78</SU>
                        <FTREF/>
                         Our assessment of the studies published since subpart W was finalized supports revising the emission factors for pipelines in the Natural Gas Distribution industry segment of subpart W.
                    </P>
                    <FTNT>
                        <P>
                            <SU>76</SU>
                             U.S. EPA. 
                            <E T="03">Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2014: Revisions to Natural Gas Distribution Emissions.</E>
                             April 2016. Available at 
                            <E T="03">https://www.epa.gov/sites/production/files/2016-08/documents/final_revision_ng_distribution_emissions_2016-04-14.pdf</E>
                             and in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>77</SU>
                             Lamb, B.K. 
                            <E T="03">et al.</E>
                             “Direct Measurements Show Decreasing Methane Emissions from Natural Gas Local Distribution Systems in the United States.” 
                            <E T="03">Environ. Sci. Technol.</E>
                             2015, 49, 5161-5169. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>78</SU>
                             Weller, Z.D.; Hamburg, S.P.; and Von Fischer, J.C. 2020. “A National Estimate of Methane Leakage from Pipeline Mains in Natural Gas Local Distribution Systems.” 
                            <E T="03">Environ. Sci. Technol.</E>
                             2020, 
                            <E T="03">54</E>
                            (1), 8958. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        The population emission factors for distribution mains and services are a function of the average measured leak rate (in standard cubic feet per hour) and the frequency of annual leaks observed (leaks/mile-year or leaks/service-year) by pipeline material (
                        <E T="03">e.g.,</E>
                         protected steel, plastic). The Lamb 
                        <E T="03">et al.</E>
                         and Weller 
                        <E T="03">et al.</E>
                         studies utilized different approaches for quantifying leak rates and determining the pipeline material-specific frequency of annual leaks. The Lamb 
                        <E T="03">et al.</E>
                         study quantified leaks from distribution mains and services using a high volume sampling method and some downwind tracer measurements and estimated the frequency of leaks by pipeline material using company records and Department of Transportation (DOT) repaired leak records from six local distribution companies (LDCs). This methodology was consistent with the 1996 GRI/EPA study. The Weller 
                        <E T="03">et al.</E>
                         study quantified leaks from only distribution mains using the Advanced Mobile Leak Detection (AMLD) technique, which involved mobile surveying using high sensitivity instruments and algorithms that predicted the leak location and size, attributed leaks to the pipeline material using geographic information system (GIS) data, and estimated the frequency of leaks using modeling.
                    </P>
                    <P>
                        In the 2022 proposed rule, we proposed to revise the pipeline main equipment leak emission factors using a combination of data from Lamb 
                        <E T="03">et al.</E>
                         (2015) and Weller 
                        <E T="03">et al.</E>
                         (2020). We sought comment on the approach of combining data from these two studies. We received numerous comments regarding the classification of pipeline materials and respective quantified leaks in the Weller 
                        <E T="03">et al.</E>
                         (2020) study. As discussed in more detail below, we agreed with commenters on the 2022 proposed rule that the categorization of pipeline leaks by material type likely resulted in inaccuracies specifically for the unprotected and protected steel pipeline material types. Therefore, in this rulemaking, we are finalizing as proposed in the 2023 Subpart W Proposal revisions of the equipment leak pipeline main emission factors using more recent study data from the Lamb 
                        <E T="03">et al.</E>
                         (2015) study.
                    </P>
                    <P>
                        In subpart W, there are currently four categories of pipeline mains: unprotected steel, protected steel, plastic, and cast iron. The steel categories are differentiated by the presence of cathodic protection, and, as evidenced by the 1996 GRI/EPA study and Lamb 
                        <E T="03">et al.</E>
                         study data, unprotected steel pipelines are considered to be more leak prone than cathodically protected steel pipelines. In the Weller 
                        <E T="03">et al.</E>
                         study, the categories of pipeline mains include bare (unprotected) steel, coated (protected) steel, cast iron, and plastic. We note that steel pipelines can be protected by cathodic protection and/or coating, and in the Weller 
                        <E T="03">et al.</E>
                         study, cathodically unprotected yet coated steel pipeline mains appear to have been grouped with cathodically protected steel pipeline mains. Using the unprotected and protected steel classifications in the Weller 
                        <E T="03">et al.</E>
                         study would thus result in emission factors for protected steel that are higher than for unprotected steel, which would conflict with other study data (
                        <E T="03">e.g.,</E>
                         1996 GRI/EPA, Lamb 
                        <E T="03">et al.</E>
                        ) as well as voluntary emissions reductions programs (
                        <E T="03">e.g.,</E>
                         EPA Natural Gas STAR). The pipeline categories in the Weller 
                        <E T="03">et al.</E>
                         study do not provide the necessary differentiation to be used to properly update the emission factors for unprotected (
                        <E T="03">i.e.,</E>
                         not cathodically protected) steel and cathodically protected steel pipeline mains. For more information on the review and analysis of the Lamb 
                        <E T="03">et al.</E>
                         and Weller 
                        <E T="03">et al.</E>
                         studies, see the subpart W TSD, available in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).
                    </P>
                    <P>
                        In consideration of our review and analysis of recent study data relative to natural gas pipeline mains and services, and consistent with the emission factors used in the 2016 U.S. GHG Inventory, we are finalizing as proposed in the 2023 Subpart W Proposal to provide emission factors for distribution pipeline mains and services based on the Lamb 
                        <E T="03">et al.</E>
                         study leak rates and the 1996 GRI/EPA study leak incidence data. For more information on the derivation of the final emission factors, see the subpart W TSD, available in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).
                    </P>
                    <P>
                        For below grade stations, the 2016 U.S. GHG Inventory also began applying a new emission factor from the data published by Lamb 
                        <E T="03">et al.</E>
                         to the count of stations to estimate emissions from these sources. In order to assess the appropriateness of incorporating this revision into the subpart W requirements for below grade stations (
                        <E T="03">i.e.,</E>
                         replacing the set of below grade emission factors by station type and inlet pressure with one single emission factor), the EPA performed an analysis of the reported subpart W data for below grade stations compared to data from the recent studies (see the subpart W TSD, available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234). We found that the subpart W reported station count combined with the current subpart W emission factors yields an average emission factor similar to the U.S. GHG Inventory emission factor; as such, using either set of emission factors would yield approximately the same emissions results for the GHGRP.
                    </P>
                    <P>
                        Therefore, we are finalizing as proposed to amend the emission factors for below grade transmission-distribution transfer stations and below grade metering-regulating stations in existing table W-7 (final table W-5) to 
                        <PRTPAGE P="42176"/>
                        subpart W to a single emission factor without regard to inlet pressure. We are also finalizing as proposed to amend the corresponding section header in existing table W-7 (final table W-5) for below grade station emission factors and the references to existing table W-7 (proposed table W-5) in 40 CFR 98.233(r)(6)(i) to clarify the emission factor that should be applied to both types of below grade stations (
                        <E T="03">i.e.,</E>
                         transmission-distribution transfer and metering-regulating). This final amendment will impact the reporting requirements in 40 CFR 98.236(r) as well, as it will consolidate six emission source types to two emission source types (below grade transmission-distribution transfer stations and below grade metering-regulating stations, without differentiating between inlet pressures) for purposes of reporting under 40 CFR 98.236(r)(1). Consistent with section II.B. of this preamble, this final amendment will improve the data quality through use of more recent emission factors and would be consistent with changes made to the U.S. GHG Inventory. It will also result in reporting of fewer data elements, consistent with section II.C. of this preamble.
                    </P>
                    <HD SOURCE="HD3">3. Gathering Pipeline Emission Factors</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        Facilities in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment currently under existing provisions quantify the emissions from equipment leaks from gathering pipelines following the procedures in 40 CFR 98.233(r). This method uses the count of equipment, subpart W population emission factors in existing table W-1A to subpart W, and operating time to estimate emissions. The population emission factors for gathering pipelines in existing table W-1A are based on leak rates from natural gas distribution companies and gathering pipeline-specific activity data as provided in the 1996 GRI/EPA study.
                        <SU>79</SU>
                        <FTREF/>
                         The population emission factors for gathering pipelines are published per mile by pipeline material.
                    </P>
                    <FTNT>
                        <P>
                            <SU>79</SU>
                             GRI/EPA. 
                            <E T="03">Methane Emissions from the Natural Gas Industry, Volume 9: Underground Pipelines.</E>
                             Prepared for Gas Research Institute and U.S. Environmental Protection Agency National Risk Management Research Laboratory by L.M. Campbell, M.V. Campbell, and D.L. Epperson, Radian International LLC. GRI-94/0257.2b, EPA-600/R-96-080i. June 1996. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <P>
                        As noted in section III.Q.2. of this preamble, the EPA is finalizing as proposed the update to the natural gas distribution population emission factors in existing table W-7 (final table W-5) to subpart W using the results of studies and information that were not available when the rule was originally finalized. In particular, the EPA is finalizing as proposed the update to the leak rate portion of the emission factor based on data published by Lamb 
                        <E T="03">et al.</E>
                         in 2015.
                        <SU>80</SU>
                        <FTREF/>
                         The EPA has reviewed the recent studies published for Onshore petroleum and natural gas gathering and boosting facilities including the Yu 
                        <E T="03">et al.</E>
                         study in the 2023 Subpart W Proposal, as well as additional studies identified in public comments, and concluded that there is currently insufficient data to update the existing emission factors with nationally representative population emission factors for gathering pipelines that are based on collection of data from gathering pipelines rather than distribution pipelines. Therefore, consistent with the updates to the emission factors for distribution mains, and consistent with section II.B. of this preamble, we are finalizing as proposed the update to the gathering pipeline population emission factors in proposed table W-1 to use the leak rates from Lamb 
                        <E T="03">et al.</E>
                         (2015). We did not propose and are not finalizing updates to the activity data (leaks per mile of pipeline) portion of the emission factors, as the information in the 1996 GRI/EPA study continues to be the best available data specific to gathering pipelines. For more information as well as responses to comments we received on the updates to the gathering pipeline population emission factors, see section 12 of the subpart W TSD and section 18.3 of the 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule,</E>
                         available in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).
                    </P>
                    <FTNT>
                        <P>
                            <SU>80</SU>
                             Lamb, B.K. 
                            <E T="03">et al.</E>
                             “Direct Measurements Show Decreasing Methane Emissions from Natural Gas Local Distribution Systems in the United States.” 
                            <E T="03">Environ. Sci. Technol.</E>
                             2015, 49, 5161-5169. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments for gathering pipelines.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters asked that the EPA provide operators with the option to use monitoring and measurement surveys to quantify gathering pipeline leak emissions.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         See the EPA's response to comments in section III.C.1.b. of this preamble requesting that the EPA allow a leaker emission factor approach and/or direct measurement of transmission pipeline leak emissions, which is also applicable to gathering pipelines and responsive to this comment.
                    </P>
                    <HD SOURCE="HD2">R. Offshore Production</HD>
                    <HD SOURCE="HD3">1. Summary of Final Amendments</HD>
                    <P>
                        Currently, subpart W requires offshore production facilities to report emissions consistent with the methods published by the U.S. Department of Interior, Bureau of Ocean Energy Management (BOEM). Since subpart W was first promulgated, there have been a number of updates to the BOEM requirements and how BOEM implements the requirements (
                        <E T="03">e.g.,</E>
                         the development of their Outer Continental Shelf Air Quality System (OCS AQS)
                        <SU>81</SU>
                        <FTREF/>
                        ), and the EPA is finalizing amendments to subpart W to reflect those changes. Specifically, the EPA is finalizing as proposed the update of the outdated acronym “BOEMRE” to the current acronym “BOEM” in 40 CFR 98.232(b), 40 CFR 98.233(s), and 40 CFR 98.236(s); the update of the cross references to the BOEM requirements from “30 CFR 250.302 through 304” to “30 CFR 550.302 through 304” in 40 CFR 98.232(b), 40 CFR 98.233(s), and the introductory paragraph of 40 CFR 98.234; and the removal of the outdated references to “GOADS” from 40 CFR 98.233(s). The EPA is also finalizing as proposed the adjustments of some of the language in 40 CFR 98.232(b) and 40 CFR 98.233(s) to more accurately reflect the current BOEM program and requirements (
                        <E T="03">e.g.,</E>
                         adjusting the number of years between BOEM data collection efforts from 4 to 3 years, referring to a published emissions inventory rather than an emissions study).
                    </P>
                    <FTNT>
                        <P>
                            <SU>81</SU>
                             For more information on this system and the emissions inventories collected by the system, see 
                            <E T="03">https://www.boem.gov/environment/environmental-studies/ocs-emissions-inventories.</E>
                        </P>
                    </FTNT>
                    <P>
                        Emissions data are collected by BOEM every few years. In years that coincide with a year in which BOEM collects data, offshore production facilities that report emissions inventory data to BOEM report the same annual emissions to subpart W as calculated and reported to BOEM (existing 40 CFR 98.233(s)(1)) and facilities that do not report emissions inventory data to BOEM must use the most recent monitoring and calculation methods published by BOEM (existing 40 CFR 98.233(s)(2)). In the intervening years, reporters currently are required to adjust emissions based on the operating time 
                        <PRTPAGE P="42177"/>
                        for the facility in the current reporting year relative to the operating time in the most recent BOEM data submission or BOEM emissions study publication year. The EPA finalizing revisions to these calculation methods based on consideration of public comments. The EPA is finalizing a requirement in 40 CFR 98.233(s)(1)(i) that if the BOEM's emissions reporting system is available and the facility has the data needed to use BOEM's emissions reporting system, reporters must calculate emissions using the most recent monitoring and calculation methods published by BOEM referenced in 30 CFR 550.302 through 304 (currently implemented through the OCS AQS). This includes years in which offshore production facilities are required to report emissions inventory data to BOEM as well as intervening years. In the final amendments, the current adjustment using operating hours in years that do not overlap with the most recent published BOEM emissions inventory or BOEM data submission, as app'icable, will only be allowed if the BOEM's emissions reporting system is not available or if the facility 'oes not have the data needed to use BOEM's emissions reporting system (which may be the case in years in which offshore production facilities are not required to report emissions inventory data to BOEM). The EPA is finalizing parallel requirements in 40 CFR 98.233(s)(2)(i) for facilities that do not report to BOEM's emissions inventory except that these requirements refer only to the calculation methods published by BOEM referenced in 30 CFR 550.302 through 304 because these facilities do not currently have access to the OCS AQS system. The 2023 Subpart W Proposal would have maintained the method of adjusting emissions using operating hours as the primary method and provided use of BOEM's monitoring and calculation methods as an alternative, but this final amendment will further improve data quality through the use of more empirical data, consistent with section II.B. of this preamble. The EPA is also amending 40 CFR 98.233(s)(3) to clarify the requirement that offshore production reporters must calculate emissions using BOEM's methods at least once every 3 years. The current rule provides provisions for delays in BOEM's data collection effort beyond 4 years, and the EPA is revising that language to specify requirements for calculation if BOEM's emissions reporting system is unavailable for more than 3 consecutive years, consistent with the updated language in 40 CFR 98.233(s)(1)(i) and (s)(2)(i).
                    </P>
                    <P>The EPA is also finalizing changes to the reporting requirements in 40 CFR 98.236. First, to improve the verification of the emissions reported by offshore production facilities to the GHGRP by establishing a definitive crosswalk between the data submitted to BOEM's Outer Continental Shelf Emissions Inventory and the GHGRP, the EPA is finalizing as proposed the requirement that offshore production facilities report the BOEM Facility ID(s) that constitute the GHGRP facility. Having a definitive point of reference between the two datasets will allow the EPA to better verify the emissions reported to the GHGRP. Second, for years in which a reporter does calculate emissions by adjusting emissions using a ratio of operating hours, the EPA is finalizing as proposed the requirement to report the facility's operating hours in the current year in 40 CFR 98.236(s)(2)(ii). The EPA is finalizing the other proposed data element, 40 CFR 98.236(s)(2)(i), with slight wording changes from proposal that reflect the final calculation methods described in the previous paragraph. Specifically, the reporter will report the facility's operating hours for the most recent year in which emissions were calculated according to either 40 CFR 98.233(s)(1)(ii) or 40 CFR 98.233(s)(2)(ii). This information will improve verification, consistent with section II.C. of this preamble. For clarification, the EPA is also finalizing a change from proposal to update 40 CFR 98.232(b) to state that offshore platforms do not need to report emissions from portable equipment, in place of the existing language that offshore platforms do not need to report portable emissions.</P>
                    <HD SOURCE="HD3">2. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments for offshore production emissions.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters suggested that instead of allowing reporters to calculate their emissions each year using BOEM's methods as an alternative to the current requirement to adjust emissions based on operating hours, the EPA should require offshore production facilities to calculate their emissions each year using BOEM's methods. While commenters expressed concern that BOEM's methods are not well-documented and currently rely mostly on emission factors, they did note that BOEM is working to incorporate additional information such as top-down data into their calculation methods, and requiring reporters to use those methods every year would at least ensure that updates to BOEM's methods are incorporated into subpart W as soon as possible. Commenters also stated that requiring use of BOEM's methods every year instead of allowing that as an option would prevent reporters from choosing the option that they predict would result in less emissions.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA has considered these comments and reviewed additional information available about BOEM's OCS AQS. We agree that directing reporters to use BOEM methods to calculate emissions every year as the primary calculation method is consistent with the directives in CAA section 136(h), including ensuring accuracy in total emissions reported for each reporting year. The final amendments to 40 CFR 98.233(s)(1)(i) and (s)(2)(i) require reporters to use BOEM's emission inventory system or calculation methods published by BOEM referenced in 30 CFR 550.302 through 304 to calculate emissions for any year in which the system is available and they have collected the necessary data to do so, including years in which facilities report emissions directly to BOEM. The final revisions allow adjustments made based on operating time as an alternative method to adjust emissions; however, the EPA is finalizing revisions to 40 CFR 98.233(s)(3) to require that facilities calculate emissions based on BOEM's calculation methods at least every 3 years.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter requested that the EPA add “fugitive sources” after “equipment leaks” in 40 CFR 98.232(b) for consistency with the BOEM's descriptions of emission source types.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA has reviewed BOEM's documentation and agrees that BOEM uses the term “fugitives” to refer to leaks from equipment components (generally referred to as “equipment leaks” in subpart W). The EPA has added the parenthetical “(
                        <E T="03">i.e.,</E>
                         fugitives)” to both 40 CFR 98.232(b) and 40 CFR 98.233(s) introductory text.
                    </P>
                    <HD SOURCE="HD2">S. Combustion Equipment</HD>
                    <HD SOURCE="HD3">1. Calculation Methodology Applicability, Higher Heating Value, and Other Calculation Methodology Clarifications</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        All facilities reporting under subpart W except those in the Onshore Natural Gas Transmission Pipeline industry segment must include combustion emissions in their annual report. Facilities in the Onshore Petroleum and 
                        <PRTPAGE P="42178"/>
                        Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural Gas Distribution industry segments calculate emissions in accordance with the provisions in 40 CFR 98.233(z) and report combustion emissions per 40 CFR 98.236(z). Reporters in the other industry segments calculate and report combustion emissions under subpart C (General Stationary Fuel Combustion Sources). Subpart W refers reporters in these segments to the calculation methodologies in subpart C to determine combustion emissions for certain fuels.
                    </P>
                    <P>The EPA is finalizing several amendments for the industry segments that report combustion equipment emissions under subpart W to improve the accuracy of the emissions calculated and therefore the quality of data collected, consistent with section II.B. of this preamble. First, we are finalizing as proposed the move of the existing provisions for fuels that do not meet the specifications to use subpart C methodologies from 40 CFR 98.233(z)(2) to a new paragraph 40 CFR 98.233(z)(3). Second, we are finalizing as proposed the move of the language in 40 CFR 98.233(z)(1)(ii) to 40 CFR 98.233(z)(5), and we are finalizing the proposed wording changes to highlight that this paragraph refers only to the requirement to report combustion emissions under subpart W. We are also finalizing as proposed the addition of a reference to this new paragraph 40 CFR 98.233(z)(5) in both 40 CFR 98.233(z)(1)(ii) and 98.233(z)(2)(ii). Third, the EPA is revising 40 CFR 98.233(z)(1) as proposed to remove the references to field gas and process vent gas and include only the characteristics for the fuels that can use subpart C methodologies. The EPA is also finalizing as proposed conforming edits to existing 40 CFR 98.233(z)(2) (final 40 CFR 98.233(z)(3)) for consistency. Fourth, as proposed, the EPA is finalizing the revision to the language in existing 40 CFR 98.233(z)(2)(ii) (final 40 CFR 98.233(z)(3)(ii)(B)) to allow the use of engineering estimates based on best available data to determine the concentration of each constituent in the flow of gas to the unit, which would allow reporters to use the best information available to determine the gas composition while maintaining the option for reporters to use 40 CFR 98.233(u)(2) if they do not have other stream-specific information. Fifth, we are finalizing as proposed the amendment of the definition of the variable for the HHV in equation W-40 in 40 CFR 98.233(z)(3)(ii) to require the use of a site-specific value.</P>
                    <P>
                        As explained in the 2023 Subpart W Proposal, the EPA proposed several revisions to address stakeholder requests to expand the ability to use subpart C calculation methodologies to additional fuel types and to improve the accuracy of the emissions calculated and therefore the quality of data collected, consistent with section II.B. of this preamble. Specifically, the EPA proposed to specify in a new paragraph in 40 CFR 98.233(z)(2) that subpart C methodologies Tier 2, Tier 3, or Tier 4 may be used to calculate emissions from the combustion of a fuel that meets the definition of “natural gas” in 40 CFR 98.238 if it has a minimum HHV of 950 Btu/scf, a maximum CO2 content of 1 percent by volume, and a minimum CH
                        <E T="52">4</E>
                         content of 85 percent by volume. We also requested comment on whether additional specification criteria should be included (e.g., a maximum HHV). After consideration of public comment, we updated our analysis of fuel compositions and our re-analysis of the data showed that maintaining the minimum HHV at 950 Btu/scf, limiting the maximum HHV to 1,100 Btu/scf, and decreasing the minimum CH
                        <E T="52">4</E>
                         content to 70 percent by volume resulted in a data set for which emissions under both subpart C (Tier 2) and subpart W were more consistently similar than the proposed parameters of maximum CO
                        <E T="52">2</E>
                         content of 1 percent by volume and a minimum CH
                        <E T="52">4</E>
                         content of 85 percent by volume. Therefore, we are finalizing in 40 CFR 98.233(z)(2) that subpart C methodologies Tier 2, Tier 3 or Tier 4 may be used to calculate emissions from the combustion of a fuel that meets the definition of “natural gas” in 40 CFR 98.238 if it has a minimum HHV of 950 Btu/scf, a maximum HHV of 1,100 Btu/scf, and a minimum CH
                        <E T="52">4</E>
                         content of 70 percent by volume.
                    </P>
                    <P>Finally, we are finalizing two amendments to provide clarity and improve understanding of the final rule, consistent with section II.D. of this preamble. We are finalizing as proposed the amendments to 40 CFR 98.233(z)(1)(ii) and existing 40 CFR 98.233(z)(2) (final 40 CFR 98.233(z)(3)(ii)) and finalizing analogous language in 40 CFR 98.233(z)(2)(ii) to clarify that emissions may be calculated for either each individual unit or groups of combustion units combusting the same fuel. In addition, based on consideration of public comments and for consistency with other paragraphs for specific emission source types, we are amending the name of 40 CFR 98.233(z) and 40 CFR 98.236(z) to remove the specific industry segment names and refer just to combustion equipment.</P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to calculation methodology applicability, HHV, and other calculation methodology clarifications (not including revisions related to methane slip).</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters requested that the EPA define “pipeline quality natural gas.” Commenters also asserted that the composition requirements in proposed 40 CFR 98.233(z)(2)(i)(B) and (C) were not justified and limited the combustion devices that would be able to use the combustion methodologies in subpart C, which would in turn limit the combustion devices that would be able to use performance test data or manufacturer provided data to calculate emissions that include methane slip.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA reviewed the comments, including the various suggested definitions of “pipeline quality natural gas,” and reviewed the analysis supporting the proposed compositions in 40 CFR 98.233(z)(2)(i)(B) and (C). First, the commenters varied in their suggested definitions, identifying two different definitions of “pipeline quality natural gas” from EPA regulations and also suggesting other provisions that they asserted are considered accepted or understood definitions of “pipeline quality natural gas.” These variations support the EPA's assertion from the 2023 Subpart W proposal that pipeline quality specifications vary across the U.S. depending on the requirements of the pipeline used to transport the gas. Therefore, the EPA is not finalizing a definition of “pipeline quality natural gas” for subpart W.
                    </P>
                    <P>
                        However, most of the specifications for pipeline quality natural gas did include a maximum HHV and a minimum CH
                        <E T="52">4</E>
                         content of 70 percent, which was lower than the proposed minimum CH
                        <E T="52">4</E>
                         content of 85 percent. The EPA did not propose to include a maximum higher heating value in 40 CFR 98.233(z)(2)(i), but the EPA did request comment on additional parameters that should be considered. When reviewing the data to assess the effect of the HHV, the EPA concluded that maintaining the minimum HHV at 950 Btu/scf, limiting the maximum HHV to 1,100 Btu/scf, and decreasing the minimum CH
                        <E T="52">4</E>
                         content to 70 percent by volume resulted in a data set for which emissions under both subpart C (Tier 2) and subpart W were more consistently 
                        <PRTPAGE P="42179"/>
                        similar than the proposed parameters of maximum CO
                        <E T="52">2</E>
                         content of 1 percent by volume and a minimum CH
                        <E T="52">4</E>
                         content of 85 percent by volume. The constituents other than CH
                        <E T="52">4</E>
                         and CO
                        <E T="52">2</E>
                         in the natural gas stream include compounds that have no heating value, such as hydrogen and nitrogen, as well as non-methane hydrocarbons and NGLs (
                        <E T="03">e.g.,</E>
                         ethane, propane, butane). The more NGLs in the stream, the more the emissions under the subpart C (Tier 2) calculations differ from the subpart W calculations, and limiting the maximum HHV reduces the number of streams with high quantities of NGLs that could use subpart C (Tier 2) methods without needing to restrict the CO
                        <E T="52">2</E>
                         content. For more information on our revised fuel composition analysis for the final rule and the comparison of emissions using various composition thresholds, see the final subpart W TSD, available in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).
                    </P>
                    <P>
                        As a result of this analysis, we are finalizing in 40 CFR 98.233(z)(2) that subpart C methodologies Tier 2 or higher may be used for fuel meeting the definition of “natural gas” in 40 CFR 98.238 if it has a minimum HHV of 950 Btu/scf, a maximum HHV of 1,100 Btu/scf, and a minimum CH
                        <E T="52">4</E>
                         content of 70 percent by volume. These specifications may in many cases be the same as the specifications for pipeline quality natural gas, but including these specifications in a separate paragraph of 40 CFR 98.233(z) maintains the flexibility to use subpart C methods both in cases where a local definition of pipeline quality natural gas might not be exactly the same as these specifications (
                        <E T="03">e.g.,</E>
                         might have a slightly larger maximum heat content) and in cases where a local definition of pipeline quality natural gas is more restrictive than these specifications.
                    </P>
                    <P>Revisions to the proposed provisions for combustion slip are addressed in section III.S.2. of this preamble.</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter suggested that the EPA should update the name of 40 CFR 93.233(z) and remove the references to the Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural Gas Distribution industry segments because the proposed provisions for combustion slip apply to all industry segments that must report combustion emissions.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA has reviewed this comment and is amending the name of 40 CFR 98.233(z) and 40 CFR 98.236(z) to remove the references to specific industry segments. The lists in 40 CFR 98.232 define which emission sources must be included in reports for each industry segment, so it is unnecessary and duplicative to include industry segment names in the emission source type paragraph names. This final amendment is also consistent with other changes to emission source type names, such as hydrocarbon liquids and produced water storage tanks in 40 CFR 98.233(j). The EPA notes that 40 CFR 98.232, specifically 40 CFR 98.232(c)(22), (i)(7), and (j)(12), continues to specify the industry segments that must calculate emissions according to 40 CFR 98.233(z) and report emissions under 40 CFR 98.236(z); this name change does not mean that additional industry segments will report combustion equipment emissions under 40 CFR 98.236(z) than under the existing requirements. The EPA is finalizing amendments to subpart C to implement revisions to account for methane slip from combustion devices in industry segments that report combustion emissions under subpart C, as described in section III.S.2. of this preamble. While those amendments cross-reference 40 CFR 98.233(z)(4), that does not make the combustion devices in industry segments that report combustion emissions under subpart C subject to 40 CFR 98.233(z) in its entirety, nor do cross-references to subpart C from 40 CFR 98.233(z)(1) and (2) make combustion equipment in the Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural Gas Distribution industry segments subject to subpart C.
                    </P>
                    <HD SOURCE="HD3">2. Methane Slip From Internal Combustion Equipment</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        The authors of several recent studies have examined combustion emissions at Onshore Petroleum and Natural Gas Gathering and Boosting facilities and have demonstrated that a significant portion of emissions can result from unburned CH
                        <E T="52">4</E>
                         entrained in the exhaust of natural gas compressor engines (also referred to as “combustion slip” or “methane slip”). These studies contend that emissions from natural gas compressor engines included in the GHGRP are significantly underestimated because they do not accurately account for combustion slip. The EPA performed a review of each of these studies and the U.S. GHG Inventory to determine whether and how combustion slip emissions have been incorporated into published data and how the incorporation of combustion slip would affect the emissions from the petroleum and natural gas system sector reported to the GHGRP (see the subpart W TSD, available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234).
                    </P>
                    <P>
                        Consistent with section II.A. of this preamble, we are revising the methodologies for determining combustion emissions from RICE and GT to account for combustion slip. For the three subpart W industry segments reporting combustion emissions under subpart W (Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural Gas Distribution), we are finalizing as proposed that RICE and GT units combusting natural gas that calculate emissions using the subpart C calculation methodologies per 40 CFR 98.233(z)(1) and 98.233(z)(2) have three options in 40 CFR 98.233(z)(4) to quantify emissions from combustion slip, including direct measurement using a performance test, the use of OEM data, or the use of default emission factors. For facilities that conduct a performance test to calculate combustion slip under 40 CFR 98.233(z)(4)(i), the performance test must be completed in accordance with one of the test methods in 40 CFR 98.234(i), which include EPA Methods 18 and 320 as well as an alternate method, ASTM D6348-12 (Reapproved 2020), 
                        <E T="03">Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy</E>
                        , Approved December 1, 2020. After consideration of public comments, we are finalizing Method 25A with nonmethane cutter as described in 40 CFR 1065.265 (as specified in table 2 of 40 CFR part 60, subpart JJJJ) as an additional test method for use in performance testing. The results of the performance test must be used to develop an emission factor for use in the CH
                        <E T="52">4</E>
                         emissions calculation. If a facility is required (for compliance with other EPA regulations) or elects to conduct a performance test for any reason (
                        <E T="03">e.g.,</E>
                         to demonstrate compliance with permit conditions, assess equipment performance), they must use the results of the performance test to calculate methane slip emissions. When multiple performance tests are completed in the same reporting year, the arithmetic average of all emission factors for the corresponding performance tests must be used in CH
                        <E T="52">4</E>
                         emissions calculation. For facilities that did not conduct a performance test for any reason and elect to use OEM data, which may include manufacturer specification sheets, emissions 
                        <PRTPAGE P="42180"/>
                        certification data, or other manufacturer data providing expected emission rates from the RICE or GT, we are finalizing as proposed that the reporter use the OEM data to develop an emission factor for use in their emissions calculations for CH
                        <E T="52">4</E>
                        . For facilities that did not conduct a performance test for any reason and elect to the use the final default emission factors, which the EPA developed using data from Zimmerle 
                        <E T="03">et al.</E>
                         (2019), we are requiring the reporter to select the appropriate emission factor by equipment type (
                        <E T="03">e.g.,</E>
                         2-stroke lean-burn, 4-stroke lean-burn, 4-stroke rich-burn, or GT) in new table W-7 rather than the emission factors in table C-2 for use in their emissions calculations for CH
                        <E T="52">4</E>
                        .
                    </P>
                    <P>
                        We proposed not to allow performance testing for facilities operating RICE and GT units combusting fuels that fall under 40 CFR 98.233(z)(3) due to variability in fuel composition. Stakeholders provided quarterly compressor station gas composition for units combusting fuels that fall under all categories described in 40 CFR 98.233. In general, we observed fuel compositions that fell under 40 CFR 98.233(z)(3) did not significantly vary more than fuels that fell under 40 CFR 98.233(z)(2), therefore we are adding performance testing as another option under 40 CFR 98.233(z)(3)(ii)(C) to determine CH
                        <E T="52">4</E>
                         emissions. Previously, for fuels under 40 CFR 98.233(z)(3), CH
                        <E T="52">4</E>
                         emissions could only be determined using a default equipment-specific combustion efficiency, provided in equations W-39A and W-39B and combined with fuel composition to calculate emissions. The second option being added for fuels under 40 CFR 98.233(z)(3) is based on direct measurement using a performance test in accordance with one of the test methods in 40 CFR 98.234(i), the same as the first option provided for natural gas that meets the specifications in either 40 CFR 98.233(z)(1) or (z)(2).
                    </P>
                    <P>
                        We expect that the records necessary to confirm the value for the development of an emission factor based on the results of a performance test or OEM data are already required to be maintained by the facility per 40 CFR 98.237; thus, no new recordkeeping provisions relative to the combustion slip amendments are being finalized. The EPA is finalizing a new reporting requirement in 40 CFR 98.236(z)(2) specifically for RICE and GT that combust natural gas that meets the criteria of 40 CFR 98.233(z)(1) or (2) or a fuel meeting the specifications of 40 CFR 98.233(z)(3) to specify the equipment type of reported internal combustion units, the method used to estimate the CH
                        <E T="52">4</E>
                         emission factor, and the value of the emission factor to facilitate verification of the reported emissions. This amendment requires the reporting of CH
                        <E T="52">4</E>
                         emissions from natural gas-fired internal combustion engine and GT units, that are grouped for reporting, must share the same equipment type (
                        <E T="03">e.g.,</E>
                         4-stroke rich burn), fuel type, and method for determining the CH
                        <E T="52">4</E>
                         emission factor, which will allow the EPA to adequately verify the data.
                    </P>
                    <P>
                        Additionally, we are finalizing as proposed that RICE or GT units in subpart W industry segments (
                        <E T="03">i.e.,</E>
                         Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural Gas Distribution) that estimate and report their combustion emissions to subpart C and currently use either equation C-8, C-8a, C-8b, C-9, C-9a, or C-10 in 40 CFR 98.33(c), as it corresponds to the Tier methodology selected to estimate their CO
                        <E T="52">2</E>
                         emissions, are required to use one of the options in 40 CFR 98.233(z)(4) to develop a CH
                        <E T="52">4</E>
                         emission factor for use in these equations to estimate CH
                        <E T="52">4</E>
                         emissions. Specifically, we are finalizing as proposed the revision to the “EF” term in each of the equations in 40 CFR 98.33(c) (
                        <E T="03">i.e.,</E>
                         equations C-8, C-8a, C-8b, C-9a, C-9b, and C-10) to reference the options for developing a CH
                        <E T="52">4</E>
                         emission factor in 40 CFR 98.233(z)(4) for natural gas-fired RICE or GT. We are also finalizing as proposed a footnote to table C-2 that specifies that for reporters subject to subpart W, the default CH
                        <E T="52">4</E>
                         emission factor in table C-2 for natural gas may only be used for natural gas-fired combustion units that are not RICE or GT.
                    </P>
                    <P>
                        Finally, we are finalizing as proposed to amend 40 CFR 98.36(b), (c)(1), and (c)(3) specifically for RICE or GT at facilities that are subject to subpart W. These provisions currently provide the requirements for reporting by emission unit, by aggregation of units or by common pipe configurations. Under the new amendments, we are requiring reporters that report emissions in accordance with 40 CFR 98.36(b), (c)(1), or (c)(3) to provide the equipment type (
                        <E T="03">e.g.,</E>
                         2-stroke lean burn RICE), the method used to determine the CH
                        <E T="52">4</E>
                         emission factor and the average value of the CH
                        <E T="52">4</E>
                         emission factor. This change will ensure that sufficient data in the overall aggregation of units or common pipe (
                        <E T="03">i.e.,</E>
                         multiple units combusting natural gas) is reported such that we can perform review of the supplied emission factor data and perform verification on the corresponding emissions. Overall, these amendments to the subpart C reporting requirements are analogous to and consistent with what is being required for RICE or GT for facilities that report combustion emissions under subpart W.
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to methane slip.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Many commenters agreed methane slip should be extended to all RICE and GTs regardless of application for all subpart W industry segments that currently report combustion emissions in subpart C or W. They acknowledged providing three methods for quantifying slip (default emission factors, direct measurement, and OEM data) for RICE and GT using natural gas outlined in 40 CFR 98.233(z)(1) and (2) increased the accuracy of reported emissions. Several commenters agreed that fuel types covered in proposed 40 CFR 98.233(z)(3) are too variable in composition and emission factors would not be representative of real operating conditions, so these fuel types should be limited to only using default combustion efficiency values. In contrast, multiple commenters suggested that the EPA allow reporters to use performance tests to develop emission factors regardless of fuel type or be able to demonstrate limited fuel variability in fuels not covered in 40 CFR 98.233(z)(1) and (2). Some commenters suggested if the operator voluntarily performs an annual performance test or performance tests required under other federal standards (NSPS Subpart JJJJ or NSPS Subpart KKKK), these results should be allowed to determine combustion slip instead of the proposed one-time performance test. Some commenters stated that, additionally, not allowing performance tests for all RICE and GT, regardless of the composition of the natural gas combusted, will disincentive operators from deploying new emerging technology meant to reduce emissions from this source category. Multiple commenters asked for clarification about the requirements for performance testing and if it was a one-time test or another required frequency.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA acknowledges the commenters' support for including combustion slip from RICE or GT irrespective of their use to drive a compressor or the industry segment in which they operate. We agree developing emission factors from direct measurement and using OEM data for these engines and turbines will help to increase the accuracy of the reported emissions. The EPA did not propose to 
                        <PRTPAGE P="42181"/>
                        allow the use of performance testing to RICE or GTs that combust fuels described in 40 CFR 98.233(z)(3) due to the suspected high variability in the fuel composition. However, stakeholders provided quarterly compressor station gas composition data for units combusting fuels that fall under all categories described in 40 CFR 98.233(z). In general, we observed fuel compositions that fell under 40 CFR 98.233(z)(3) did not significantly vary more than fuels that fell under 40 CFR 98.233(z)(2); therefore, for facilities operating RICE and GT units combusting fuels that fall under 40 CFR 98.233(z)(3), we are adding performance testing as another option to determine CH
                        <E T="52">4</E>
                         emissions. We are finalizing an amendment to further extend the use of performance testing to fuels that do not meet the natural gas specifications in 40 CFR 98.233(z)(1) or (2), as described in 40 CFR 98.233(z)(3). If a facility combusting a fuel as described in 40 CFR 98.233(z)(3)(i) elects to conduct a performance test in accordance with 40 CFR 98.233(z)(4)(i) for any reason (
                        <E T="03">i.e.,</E>
                         assess equipment performance, provide data to meet company emission reduction goals, demonstrate compliance with permits or regulations), the result of this performance test would be required to be used to develop an emission factor and used in equation W-40 of 40 CFR 98.234(z)(3)(ii)(G) to estimate CH
                        <E T="52">4</E>
                         emissions, consistent with the approach proposed and finalized for 40 CFR 98.233(z)(2). Additionally, when multiple performance tests are completed in the same reporting year, the arithmetic average of all emission factors for the corresponding performance tests must be used in CH
                        <E T="52">4</E>
                         emissions calculation. A facility that has not performed a performance test for any reason must calculate their methane emissions as provided in 40 CFR 98.234(z)(3)(ii)(D) using equipment specific default combustion factors with equation W-39B. We did not include a performance testing frequency for fuels subject to 40 CFR 98.233(z)(3) because of their low compositional variability, which is consistent with what we proposed and are finalizing for fuels subject to 40 CFR 98.233(z)(1) or (2). By further extending the use of direct measurement, reporters have both a measurement and default option for additional fuels used in RICE and GTs, consistent with directives in CAA section 136 and will help incentivize the deployment of new technology meant to reduce emissions. For more information on our evaluation, see the subpart W TSD, available in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Multiple commenters suggested adding additional test methods for use in performance testing to measure CH
                        <E T="52">4</E>
                         concentrations. Some of the commenters recommended adding Method 25A with nonmethane cutter as described in 40 CFR 1065.265 (as specified in table 2 of 40 CFR part 60, subpart JJJJ). Commenters noted the nonmethane cutter test method would allow for continuity in testing procedures currently in place and allowed by both the EPA and state agencies. Commenters stated that, additionally, this method would decrease the burden related to operators having to perform multiple tests to comply with different requirements of subpart W and better align with tests conducted for NSPS JJJJ and NSPS ZZZZ. One commenter recommended adding ASTM 6348-03, Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy or portable fuel meters and thermodynamic software to determine true horsepower to determine emission factors of methane. The commenter suggested performance testing allows operators to diagnose engine problems, that normally go undetected, resulting in cleaner burning engines with improved performance.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The addition of performance testing for all natural gas fuels combusted in RICE and GT will improve the accuracy for CH
                        <E T="52">4</E>
                         emission reporting in the GHGRP and align with the directives in CAA section 136. To further increase flexibility and alignment with other regulatory requirements, the EPA reviewed and is adding Method 25A with Nonmethane cutter as described in 40 CFR 1065.265 to the approved testing methodologies listed in final 40 CFR 98.234(i). The EPA does not agree with including ASTM 6348-03, as it has been superseded by a more recent version. Instead, the alternate method ASTM 6348-12 (Reapproved 2020) is being finalized as an approved testing methodology in 40 CFR 98.234(i). This method is the most current version for the “Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy.” Additionally, the EPA does not agree with allowing thermodynamic software to determine horsepower and subsequently back calculating the CH
                        <E T="52">4</E>
                         emission factor. The use of thermodynamic software in this way is useful for diagnosing engine problems but has not been studied for its accuracy for determining CH
                        <E T="52">4</E>
                         emissions. The EPA may add additional methods to 40 CFR 98.234(i) in future amendments through a rulemaking process.
                    </P>
                    <HD SOURCE="HD3">3. Location of Reporting Requirements for Combustion Equipment</HD>
                    <P>
                        As noted in section III.S.1. of this preamble, facilities in the Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural Gas Distribution industry segments must calculate combustion emissions in accordance with 40 CFR 98.233(z) and report emissions under existing subpart W. Facilities in the remaining industry segments (
                        <E T="03">i.e.,</E>
                         Offshore Petroleum and Natural Gas Production, Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, LNG Storage, and LNG Import and Export Equipment) are required to calculate combustion emissions in accordance with the provisions of 40 CFR 98.33 and report emissions under subpart C.
                    </P>
                    <P>
                        In the 2023 Subpart W Proposal, the EPA requested comment on amending subpart W to specify that all industry segments would be required to report their combustion emissions, including CH
                        <E T="52">4</E>
                        , under subpart W to more accurately reflect the total CH
                        <E T="52">4</E>
                         emissions from such facilities within the emissions reported under subpart W. The EPA received comments supporting the reporting of all combustion emissions under subpart W but also received comments suggesting that the EPA instead should require reporting of all combustion emissions under subpart C, including combustion emissions from the Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural Gas Distribution industry segments that are currently reported under subpart W. The EPA evaluated the comments and has decided not to take final action on any of the requested changes to 40 CFR 98.232 regarding which industry segments must report combustion emissions under subpart W.
                    </P>
                    <P>
                        Section 136(h) of the CAA specifies that the EPA shall “revise the requirements of subpart W . . . to ensure the reporting under such subpart . . . accurately reflect[s] the total methane emissions and waste emissions from the applicable facilities.” Sections 136(c) and (e) of the CAA specify that the waste emissions charge provisions apply to emissions reported pursuant to subpart W, and CAA section 136(d) indicates that the term “applicable facility” means a facility within an 
                        <PRTPAGE P="42182"/>
                        affected industry segment, as defined in subpart W. At the time that Congress drafted CAA section 136, the existing reporting structure in which combustion emissions are reported under subpart C for some industry segments and subpart W for other industry segments was already established. Under CAA section 136(d), the nine affected industry segments are categorized into four groups, and a waste emissions threshold is applied to each of the four. Congress was aware of this reporting struXXXndustryen it enacted CAA section 136 and established the industry segment-specific thresholds. The EPA finds no indication in the text of CAA section 136 suggesting that the thresholds should be applied to an alternative to the existing reporting structure regarding combustion emissions under subpart W.
                    </P>
                    <HD SOURCE="HD2">T. Leak Detection and Measurement Methods</HD>
                    <HD SOURCE="HD3">1. Acoustic Leak Detection</HD>
                    <P>
                        For emission source types for which measurements are required, subpart W specifies the methods that may be used to make those measurements in 40 CFR 98.234(a). To improve the quality of the data when an acoustic leak detection device is used, consistent with section II.B. of this preamble, we are finalizing as proposed two revisions to the acoustic measurement requirements in 40 CFR 98.234(a)(5). First, for stethoscope type acoustic leak detection devices (
                        <E T="03">i.e.,</E>
                         those designed to detect through-valve leakage when put in contact with the valve body and that provide an audible leak signal but do not calculate a leak rate), we are finalizing as proposed that a leak is detected if an audible leak signal is observed or registered by the device. Second, we are finalizing as proposed that if a leak is detected using a stethoscope type device, then that leak must be measured using one of the quantification methods specified in 40 CFR 98.234(b) through (d) and that leak measurement must be reported regardless of the volumetric flow rate measured. These revisions will improve the accuracy of emissions reported for compressors and transmission tanks when an acoustic leak detection device is used. The EPA received only supportive comments regarding the revisions for acoustic leak detection devices. See the document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
                    </P>
                    <HD SOURCE="HD3">2. High Volume Samplers</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        We are finalizing as proposed two revisions to the high volume sampler methods to improve the quality of the data when high volume samplers are used for flow measurements, consistent with section II.B. of this preamble. First, we are adding detail to 40 CFR 98.234(d)(3) to clarify the calculation methods associated with high volume sampler measurements. Generally, high volume samplers measure CH
                        <E T="52">4</E>
                         flow, not whole gas flow. However, the current calculation methods in 40 CFR 98.234(d)(3) treat the measurement as a whole gas measurement. Therefore, we are clarifying the calculation methods needed if the high volume sampler outputs CH
                        <E T="52">4</E>
                         flow in either a mass flow or volumetric flow basis. Specifically, we are finalizing as proposed methods to determine natural gas (whole gas) flows based on measured CH
                        <E T="52">4</E>
                         flows.
                    </P>
                    <P>
                        Second, we are finalizing as proposed to add a paragraph at 40 CFR 98.234(d)(5) to clarify how to assess the capacity limits of a high volume sampler. Currently, 40 CFR 98.234(d) simply states to “Use a high volume sampler to measure emissions within the capacity of the instrument”; there is no other information provided to clarify what “within the capacity of the instrument” means or how it is determined. Considering actual sampling rates, gas collection efficiencies near the sampling rates, and reported CH
                        <E T="52">4</E>
                         quantitation limits relative to maximum sampling rates, we determined that whole gas flow rates exceeding 70 percent of the device's maximum rated sampling rate is an indication that the device will not accurately quantify the volumetric emissions, which we deem to exceed the capacity of the device. Therefore, we are finalizing as proposed the specification that CH
                        <E T="52">4</E>
                         flows above the manufacturer's CH
                        <E T="52">4</E>
                         flow quantitation limit or total volumetric flows exceeding 70 percent of the manufacturer's maximum sampling rate indicate that the flow is beyond the capacity of the instrument and that flow meters or calibrated bags must be used to quantify the flow rate. However, after consideration of public comment, we are providing an allowance for reporters that use OGI to ensure that there is 100 percent capture of the leak emissions during the entire high volume sampling period to be able to use the measured flow rate even where it exceeds 70 percent of the manufacturer's maximum sampling rate. If emissions are observed escaping capture from the high volume sampler when using OGI to ensure capture, then that measurement is considered invalid (
                        <E T="03">i.e.,</E>
                         considered to be exceeding the quantitation capacity of the device) even if the measured flow rate is less than 70 percent of the sampling rate. For more information on our review, see the subpart W TSD, available in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments for high flow samplers.</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter noted that because a high volume analyzer captures the emissions, OGI can be used to ensure that the high volume analyzer is collecting all of the emissions in its vicinity. The commenter stated that the EPA should clarify that an operator using OGI to ensure that a high volume analyzer is capturing all emissions may rely on the manufacturer's information on capacity limitations when reporting emissions.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         We agree with the commenter that OGI can be used to ensure that there is 100 percent capture of the leak emissions during the entire high volume sampling period, but we also note that OGI observations may also be used to indicate that 100 percent capture is not achieved. We have revised 40 CFR 98.234(d)(5) to specify that if 100 percent capture is documented throughout the measurement period by OGI, then the measured flow rate above the 70 percent maximum sampling rate provision can be used. However, if any emissions are observed escaping capture of the high volume sampler during a measurement period, then that measurement is considered invalid (
                        <E T="03">i.e.,</E>
                         considered to be exceeding the quantitation capacity of the device) even if the measured flow rate is less than 70 percent of the sampling rate because the high volume sampler did not capture 100 percent of the emissions during that measurement period. We selected 70 percent of the manufacturer's maximum sampling rate as a reasonable proxy for efficient capture, but actual sampling rates may be lower depending on the battery power. Also, capture efficiency may be impacted by how the emissions are released from the leak source. We did not require OGI observations, but we agree that OGI observations provide an empirical means by which to assess capture efficiency and are preferred to 
                        <PRTPAGE P="42183"/>
                        and override the 70 percent maximum sampling rate criteria when OGI observations are used.
                    </P>
                    <HD SOURCE="HD2">U. Industry Segment-Specific Throughput Quantity Reporting</HD>
                    <HD SOURCE="HD3">1. Throughput Information for the Future Implementation of the Waste Emissions Charge</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>As noted in section I.E. of this preamble, CAA section 136(f) specifies segment-specific thresholds (Waste Emissions Thresholds) for segments subject to the WEC. For the Onshore Petroleum and Natural Gas Production and Offshore Petroleum and Natural Gas Production industry segments, the Waste Emissions Threshold is specified in CAA section 136(f)(1) as, “(A) 0.20 percent of the natural gas sent to sale from such facility;” or “(B) 10 metric tons of methane per million barrels of oil sent to sale from such facility, if such facility sent no natural gas to sale.” For the Onshore Petroleum and Natural Gas Gathering and Boosting, Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, LNG Storage, LNG Import and Export Equipment, and Onshore Natural Gas Transmission Pipeline industry segments, the Waste Emissions Threshold is defined in CAA section 136(f)(2) and (3) as a percentage of “natural gas sent to sale from or through such facility,” with the percentages specified varying by segment.</P>
                    <P>To align the subpart W reporting elements with text used in CAA section 136 and enable verification of throughput-related reporting elements, consistent with section II.C. of this preamble, the EPA is finalizing as proposed to add a combination of new reporting elements and amendments to existing segment-specific throughput reporting requirements in 40 CFR 98.236(aa).</P>
                    <P>The EPA is finalizing as proposed to add the word “natural” in front of “gas” at each occurrence where it is used in the throughput reporting elements in subpart W that are being revised to align with CAA section 136. We note that the CAA section 136 text uses the term “oil” and we are clarifying in this preamble that for the purposes of the waste emissions charge the term “oil” in CAA section 136 has the same meaning as “crude oil” as used in subpart W (which is used in the throughput reporting elements in subpart W and defined in subpart A of part 98).</P>
                    <P>The EPA is finalizing as proposed revisions to ensure that the verbiage of “sent to sales” or “through the facility” is reflected in the reporting elements, as applicable. The EPA is also finalizing as proposed in 40 CFR 98.236(aa) that the quantities sent to sales or through the facility be measured, as it is reasonable to expect that the quantities of these products are already closely tracked by reporters. The EPA expects that gas and hydrocarbon liquids are typically sold by the cubic foot or barrel, respectively, so measurements are important for owners and operators to determine the correct sales prices. Similarly, it is important to track quantities sent through the facility for a variety of reasons, such as ensuring that processes at the facility are optimized or meeting contractual obligations for transferring gas or hydrocarbon liquids to another owner or operator.</P>
                    <P>
                        Subpart W currently requires onshore natural gas processing facilities to report the quantity of natural gas received at the gas processing plant in existing 40 CFR 98.236(aa)(3)(i); however, the rule does not currently specify whether the volume is all natural gas that enters the facility—including natural gas that passes through the facility without being processed further (
                        <E T="03">i.e.,</E>
                         “pass-through volumes”)—or just natural gas received for processing. As discussed in section III.U.4. of this preamble, to maintain consistency with subpart NN and reduce burden for fractionators, the EPA is finalizing revisions to 40 CFR 98.236(aa)(3)(i) as proposed to specify that the subpart W quantity of gas received is the gas received for processing and is also finalizing as proposed to specify that fractionators do not have to report a quantity under 40 CFR 98.236(aa)(3)(i) if they report under subpart NN.
                    </P>
                    <P>
                        However, to be consistent with CAA section 136(f)(2), the throughput should include all volumes of natural gas that pass through the facility or are sent to sales. Therefore, considering the amendments to 40 CFR 98.236(aa)(3)(i) and guidance that has been historically provided for 40 CFR 98.236(aa)(3)(ii) (as explained in the preamble to the 2023 Subpart W Proposal), a new reporting element for natural gas processing throughput is needed to fully capture all volumes through the facility (
                        <E T="03">i.e.,</E>
                         those that are processed and those that pass through the facility which are not processed). As such, we are finalizing the new reporting element for the Onshore Natural Gas Processing industry segment in 40 CFR 98.236(aa)(3)(ix) as proposed to capture all natural gas that is processed and/or passed through the facility, consistent with the text in CAA section 136 (
                        <E T="03">i.e.,</E>
                         “natural gas sent to sale from or through facilities”).
                    </P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed general amendments to throughput information for the future implementation of the waste emissions charge.</P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter stated that the EPA must expand the allowable methods to measure hydrocarbon liquid throughputs. The commenter stated that liquid throughputs are not commonly measured with flow meters but are instead usually determined by truck loading tickets, so the requirement to use a flow meter to determine quantities sent to sale or through the facility is not workable for hydrocarbon liquids.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         In assessing these commenters' assertion, the EPA reviewed available information about available flow meters to independently verify the commenters' claim and found that hydrocarbon liquids may be measured with meters such as ultrasonic and turbine flow meters. Ultrasonic flow measurement technology has been recognized in Chapter 5.8 of the API document, 
                        <E T="03">Manual of Petroleum Measurement Standards</E>
                        .
                        <SU>82</SU>
                        <FTREF/>
                         These meters “infer the volumetric throughput by measuring the velocity over the flow area.” 
                        <SU>83</SU>
                        <FTREF/>
                         However, temperature is necessary to consider for crude oils as this can significantly change a meter's performance due to change in viscosity. The viscosity of each product needs to be specified over the operating temperature range. Further, we recognize that ultrasonic flow meters are Reynolds Number dependent and may be affected by the relationship between velocity and viscosity as well as by entrained solids, water, gas, and wax.
                        <SU>84</SU>
                        <FTREF/>
                         Additionally, turbine flow meters may be used to “indicate flow rate and measure total throughput of a liquid line.” 
                        <SU>85</SU>
                        <FTREF/>
                         Manufacturers of turbine flow 
                        <PRTPAGE P="42184"/>
                        meters state, “Typical fluids and gases measured with turbine meters include hydrocarbons, chemicals, water, cryogenic liquids, air, natural gas, and industrial gases.” 
                        <SU>86</SU>
                        <FTREF/>
                         Therefore, the EPA is finalizing the requirements to determine throughput quantities that are sent to sale or through the facility using a flow meter that meets the requirements of 40 CFR 98.234(b).
                    </P>
                    <FTNT>
                        <P>
                            <SU>82</SU>
                             API. 
                            <E T="03">Manual of Petroleum Measurement Standards</E>
                            , Chapter 5.8: Measurement of Liquid Hydrocarbons by Ultrasonic Flow Meters Using Transit Time Technology. ANSI/API MPMS Ch. 5.8-2011. 2nd Edition, November 2011 (Errata 1 dated February 2014).
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>83</SU>
                             Kalivoda, R. F
                            <E T="03">lowmeter Application Considerations: Knowing the Limits of Ultrasonics for Crude Oil Measurement.</E>
                             September 26, 2010. Available at 
                            <E T="03">https://www.piprocessinstrumentation.com/home/article/15554208/flowmeter-application-considerations</E>
                            , last accessed April 12, 2024. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>84</SU>
                             
                            <E T="03">Id.</E>
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>85</SU>
                             Cameron. Technical Specifications: NUFLO Liquid Turbine Flow Meters. 2013. 
                            <E T="03">https://www.anythingflows.com/es/wp-content/uploads/2016/05/nuflo-liquid-turbine-flow-meters_fpd.pdf.</E>
                              
                            <PRTPAGE/>
                            Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <FTNT>
                        <P>
                            <SU>86</SU>
                             Hoffer Flow Controls, “Turbine Flow Meters.” 
                            <E T="03">https://hofferflow.com/turbine-flow-meters</E>
                            , last accessed April 12, 2024. Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                        </P>
                    </FTNT>
                    <HD SOURCE="HD3">2. Throughput Information for the Future Implementation of the Waste Emissions Charge for Onshore Petroleum and Natural Gas Production and Offshore Petroleum and Natural Gas Production</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>For the Onshore Petroleum and Natural Gas Production and Offshore Petroleum and Natural Gas Production industry segments, the current requirements for reporting throughputs of crude oil are combined with volumes of condensate. The EPA proposed to separate of these reporting elements into two distinct reporting elements in both 40 CFR 98.236(aa)(1)(i) and 98.236(aa)(2) based on a preliminary determination that these volumes will need to be reported separately in order to align with the CAA section 136(f) oil threshold for production facilities, when applicable. However, after further consideration and review of public comments, the EPA is not taking final action on that proposed revision. The existing definitions of “sales oil” and “crude oil” in subpart A both include condensate, and there is no indication that the phrase “oil sent to sale” as used in CAA section 136(f)(1) should be defined differently than the definitions subpart A.</P>
                    <P>For consistency with CAA section 136, the EPA is finalizing as proposed to use the phrase “sent to sale” in 40 CFR 98.236(aa)(1)(i)(B) and (C) and 40 CFR 98.236(aa)(2)(i) and (ii) instead of “for sale,” the phrase used in some of the existing data elements. This amendment is for consistency in language rather than any expected difference in the volumes to be reported or the interpretation of the terms, as the existing term was intended to have the same meaning.</P>
                    <P>Specifically for the Offshore Petroleum and Natural Gas Production industry segment, the existing throughput requirements are for “gas handled” and “oil and condensate handled” at the platform, which includes production volumes as well as volumes transferred via pipeline from another location. In order to provide consistency with the language in CAA section 136 across both production industry segments and help the EPA implement CAA section 136, the EPA is finalizing as proposed the revision of the reporting elements in 40 CFR 98.236(aa)(2) for the Offshore Petroleum and Natural Gas Production industry segment so they are analogous to those in Onshore Petroleum and Natural Gas Production.</P>
                    <P>
                        The EPA is also finalizing additional throughput data elements to provide separate, well-level reporting of throughputs associated with wells in the Onshore Petroleum and Natural Gas Production and Offshore Petroleum and Natural Gas Production industry segments that are permanently shut-in and plugged. These data elements are anticipated to be necessary for the implementation of the associated exemption in CAA section 136(f)(7). Specifically, in the 2024 WEC Proposal, the EPA proposed that these data elements would be used as equation inputs for the purposes of calculating emissions attributable to a permanent shut-in and plugged well for wells in the Onshore Petroleum and Natural Gas Production industry segment in reporting year 2024 and for wells in the Offshore Petroleum and Natural Gas Production in any reporting year. First, the EPA is finalizing as proposed to revise the phrase “permanently taken out of production (
                        <E T="03">i.e.</E>
                        , plugged and abandoned)” in proposed 40 CFR 98.236(aa)(1)(ii)(D) and (H) to read “permanently shut-in and plugged” for consistency with the language used in CAA section 136. This amendment is for consistency in language rather than any expected difference in the wells to be reported or the interpretation of the terms. Second, the EPA is finalizing as proposed to require reporting of the quantities of natural gas and crude oil produced that is sent to sale during the reporting year for each well that is permanently shut-in and plugged. However, as discussed earlier in this section, the EPA is not taking final action on the proposed revision to require separate reporting for crude oil and condensate, so the final amendments require reporting of natural gas in 40 CFR 98.236(aa)(1)(iii)(C) and 40 CFR 98.236(aa)(2)(iii) and crude oil (including condensate) in 40 CFR 98.236(aa)(1)(iii)(D) and 40 CFR 98.236(aa)(2)(iv) for the Onshore Petroleum and Natural Gas Production industry segment and the Offshore Petroleum and Natural Gas Production industry segment, respectively.
                    </P>
                    <P>Based on consideration of public comments, as well as the recent 2024 WEC Proposal, the EPA is not taking final action at this time on the proposed revision to require each Onshore Petroleum and Natural Gas Production well-pad with a well that was permanently shut-in and plugged to report the total quantities of natural gas, crude oil, and condensate produced that is sent to sale in the reporting year for the wells on that well-pad. The EPA proposed these data elements anticipating that they may be necessary for the exemption in CAA section 136(f)(7) for wells that are permanently shut-in and plugged. However, the 2024 WEC Proposal does not use these data elements for the purposes of determining the quantity of emissions that may be exempted for a well that was permanently shut-in and plugged.</P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to throughput information for the future implementation of the waste emissions charge for the Onshore Petroleum and Natural Gas Production and Offshore Petroleum and Natural Gas Production industry segments.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters disagreed with the EPA's proposal to require separate reporting of crude oil and condensate and explained that oil and condensate are often sold as one combined volume. Commenters explained that for offshore production facilities in particular, oil and condensate produced is sent onshore via single combined pipelines. Commenters stated that subpart A defines “sales oil” as produced crude oil or condensate measured at the production lease automatic custody transfer meter or custody transfer tank gauge and do not measure oil or condensate separately. One commenter stated that the IRA does not differentiate between oil, condensate, and natural gas.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         After further review of the requirements in CAA section 136, we agree that it is not necessary for condensate to be reported separately from crude oil. Section 136(f)(1) of the CAA uses the phrase “barrels of oil sent to sale,” and there is no indication that “oil sent to sale” should be defined differently than the term “sales oil” that already exists in subpart A. As the commenters noted, the definition of “sales oil” includes condensate, and the definition of “crude oil” in subpart A also includes condensate. Therefore, the 
                        <PRTPAGE P="42185"/>
                        EPA agrees that the amendment to use the term “sent to sale” in 40 CFR 98.236(aa)(1)(i)(C), 40 CFR 98.236(aa)(1)(iii)(D), and 40 CFR 98.236(aa)(2)(ii) and (iv) should address concerns with consistency with CAA section 136.
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters stated the proposal to require each Onshore Petroleum and Natural Gas Production well-pad with a well that was permanently shut-in and plugged to report the total quantities of natural gas, crude oil, and condensate produced that is sent to sale in the reporting year for the wells on that well-pad would result in duplicative reporting and is unnecessary.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         At the time of proposal, the EPA anticipated that these data elements may be useful in the future evaluation of the associated exemptions in CAA section 136(f)(7). However, the proposed provisions for the exemption for permanently shut-in and plugged wells in the 2024 WEC Proposal do not use the total quantities of natural gas and crude oil sent to sale in the reporting year for the wells on that well-pad. Therefore, we are not finalizing the requirement for reporting of throughput for each well-pad with a well that was permanently shut-in and plugged at this time.
                    </P>
                    <HD SOURCE="HD3">3. Throughput Information for the Future Implementation of the Waste Emissions Charge for Onshore Petroleum and Natural Gas Gathering and Boosting</HD>
                    <HD SOURCE="HD3">a. Summary of Final Amendments</HD>
                    <P>
                        To be consistent with the EPA's original intent for the throughput volumes for the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment, the EPA is finalizing amendments to 40 CFR 98.236(aa)(10)(ii) and (iv) with changes from proposal. We proposed to clarify that the downstream endpoints listed in the current reporting elements are examples of potential destinations. Based on consideration of public comment and further review of the language and background documentation, the EPA is instead revising 40 CFR 98.236(aa)(10)(ii) and (iv) to specify that the reported quantities should be the natural gas or hydrocarbon liquids, respectively, transported from the facility (rather than specifying that the reported quantities should be the natural gas or hydrocarbon liquids, respectively, transported to downstream operations such as one of those endpoints, as proposed). However, some gas may flow back upstream, for use at an onshore petroleum and natural gas facility. Section 136(f)(2) of the CAA indicates that the WEC should be based on the “natural gas sent to sale from or through such facility” but does not specify that the gas must be sent from the facility to a downstream endpoint. As a result of these amendments, the reported quantities must include all natural gas and hydrocarbon liquids transported from the facility (
                        <E T="03">i.e</E>
                        ., transported to another basin, transported to another gathering system owner or operator, or transported outside of the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment).
                    </P>
                    <P>In addition to reviewing the reported throughputs, we also reviewed the definitions in subpart W associated with the industry segment and the facility, specifically the definitions for “gathering and boosting system” and “gathering and boosting system owner or operator” in 40 CFR 98.238. We are finalizing as proposed to amend the definition of “gathering and boosting system” and “gathering and boosting owner or operator” in 40 CFR 98.238 to specify that these systems may receive natural gas and/or petroleum from one or more other onshore petroleum and natural gas gathering and boosting systems in addition to production facilities. We are also finalizing additional amendments to clarify that the downstream endpoints listed in the current provisions are examples of potential destinations. Specifically, we are revising the definition of “gathering and boosting system owner or operator” in 40 CFR 98.238 and the description of the industry segment in 98.230(a)(9) to add the phrase “a downstream endpoint, typically” before the list of the types of facilities that may receive the petroleum and/or natural gas.</P>
                    <HD SOURCE="HD3">b. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed amendments to throughput information for the future implementation of the waste emissions charge for the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Commenters supported the EPA's proposed changes to the gathering and boosting throughput reporting requirements but noted that the term “downstream endpoint” is too narrow because gas sometimes exits the gathering system to an “upstream” location, such as back to upstream producers for various uses. Commenters also requested that the EPA specify that Onshore Petroleum and Natural Gas Gathering and Boosting industry segment reporters should account for gas that flows through multiple compressor stations (“sites”) in series within the same basin by revising the list of examples of downstream endpoints to include “another gathering and boosting site or facility.”
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The EPA agrees with the commenters' statement that “downstream endpoint” is too narrow and that it would be more accurate for facilities to report all natural gas and hydrocarbon liquids transported from the facility regardless of destination, including quantities that are transported to another basin, quantities that are transported to another gathering system owner or operator, and quantities that are transported to a facility in a different industry segment or source category. In response to this comment, the EPA is finalizing amendments to 40 CFR 98.236(aa)(10)(ii) to specify that the natural gas is transported “from the facility,” regardless of whether the endpoint is downstream of the facility.
                    </P>
                    <P>However, the EPA disagrees with the commenters' request to report the total throughput reported as the quantity transported from each gathering and boosting site where that quantity is transported to a site that is part of the same facility with respect to onshore petroleum and natural gas gathering and boosting. This would allow reporters to count flows multiple times and significantly increase the throughput volumes for gathering and boosting facilities. Congress established methane waste emissions thresholds for gathering and boosting facilities under CAA section 136 with reference to the existing subpart W facility definitions. The EPA proposed revisions to the throughput requirements that would align with the requirements of CAA section 136. The EPA generally proposed to maintain the existing approach to facility throughputs, with limited revisions to ensure that all throughput transported from the facility is included and to align with the terminology used in CAA section 136.</P>
                    <HD SOURCE="HD3">4. Onshore Natural Gas Processing and Natural Gas Distribution Throughputs Also Reported Under Subpart NN</HD>
                    <P>
                        For the reasons stated in the preamble to the 2023 Subpart W Proposal, the EPA is finalizing as proposed the elimination of duplicative elements from subpart W for facilities that report to subpart NN and two other data elements for natural gas distribution companies, consistent with section II.C. of this preamble. The EPA received only supportive comments regarding the removal of these data elements from subpart W. See the document 
                        <E T="03">
                            Summary 
                            <PRTPAGE P="42186"/>
                            of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule
                        </E>
                         in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
                    </P>
                    <P>Onshore Natural Gas Processing plants are required to report seven facility-level throughput-related items under subpart W, as specified in existing 40 CFR 98.236(aa)(3). These seven data reporting elements include: quantities of natural gas received and processed gas leaving the gas processing plant, cumulative quantities of NGLs received and leaving the gas processing plant, the average mole fractions of CH4 and CO2 in the natural gas received, and an indication of whether the facility fractionates NGLs. The EPA is finalizing several reporting requirements in 40 CFR 98.236(aa)(3) as proposed for Onshore Natural Gas Processing plants that both fractionate NGLs and also report as a supplier under subpart NN. First, to clarify which facilities have data overlap between subparts W and NN, the EPA is adding a reporting element for natural gas processing plants at 40 CFR 98.236(aa)(3)(viii) to indicate whether they report as a supplier under subpart NN. We note that the final wording for this new data element is slightly changed from proposal to clarify that the facility report must include subpart NN data under the same e-GGRT identification number and the same calendar year as the Onshore Natural Gas Processing plant. Some facilities may not report under both subparts ever year, or some owners or operators may choose to report subpart NN data using a different e-GGRT identification number, and the language of the final data element clarifies how a reporter should respond to the data element. Next, the EPA is finalizing as proposed to specify in 40 CFR 98.236(aa)(3) introductory text that facilities that indicate that they both fractionate NGLs and report as a supplier under subpart NN under the same e-GGRT identification number and for the same calendar year would no longer be required to report the quantities of natural gas received or NGLs received or leaving the gas processing plant as specified in 40 CFR 98.236(aa)(3)(i), (iii) and (iv); this data will continue to be reported under subpart NN as specified in 40 CFR 98.406(a)(3), 98.406(a)(1) and (2), 98.406(a)(4)(i) and (ii), respectively, thus, maintaining the ability to verify associated emissions reported under subpart W. See table 2 of this preamble for more information.</P>
                    <P>These facilities will be required to continue reporting the data elements specified in 40 CFR 98.236(aa)(3)(ii) and (v) through (viii), as these reporting elements do not overlap with subpart NN reporting elements. Natural gas processing plants that do not fractionate or that fractionate but do not report as a supplier under subpart NN will continue to report all of the reporting elements for natural gas processing plants as specified in 40 CFR 98.236(aa)(3).</P>
                    <P>Natural Gas Distribution companies are also required to report seven throughput volumes under subpart W, as specified in existing 40 CFR 98.236(aa)(9). These seven data reporting elements include: the quantity of gas received at all custody transfer stations; the quantity of natural gas withdrawn from in-system storage; the quantity of gas added to in-system storage; the quantity of gas delivered to end users; the quantity of gas transferred to third parties; the quantity of gas consumed by the LDC for operational purposes; and the quantity of gas stolen. The EPA is finalizing the removal of the duplicative reporting elements for throughput for LDCs in 40 CFR 98.236(aa)(9)(i) through (iv), as proposed. See table 3 of this preamble for more information.</P>
                    <P>Finally, the EPA is finalizing as proposed to remove the reporting elements for the volume of natural gas used for operational purposes and natural gas stolen specified in 40 CFR 98.236(aa)(9)(vi) and (vii). As a result of removing all of the 40 CFR 98.236(aa)(9) data elements for the reasons explained in this section of this preamble, the EPA is reserving paragraph 40 CFR 98.236(aa)(9).</P>
                    <P>Table 2 of this preamble shows all the duplicative data elements that the EPA is removing from subpart W for facilities that also report to subpart NN.  </P>
                    <GPH SPAN="3" DEEP="640">
                          
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                    <PRTPAGE P="42188"/>
                    <HD SOURCE="HD3">5. Onshore Natural Gas Transmission Pipeline Throughputs</HD>
                    <P>Similar to Natural Gas Distribution facilities, Onshore Natural Gas Transmission Pipeline facilities are currently required to report five throughput volumes under subpart W, as specified in existing 40 CFR 98.236(aa)(11). These five data reporting elements include: the quantity of natural gas received at all custody transfer stations; the quantity of natural gas withdrawn from in-system storage; the quantity of gas added to in-system storage; the quantity of gas transferred to third parties; and the quantity of gas consumed by the transmission pipeline facility for operational purposes. For the reasons stated in the preamble to the 2023 Subpart W Proposal, the EPA is finalizing as proposed to amend 40 CFR 98.236(aa)(11)(ii) and (iii) to replace the term “in-system” with clarifying language that specifies withdrawals/additions of natural gas from storage are referring to Underground Natural Gas Storage and LNG Storage facilities that are owned and operated by the onshore natural gas transmission pipeline owner or operator that do not report under subpart W as direct emitters themselves. These amendments are expected to improve data quality consistent with section II.D. of this preamble. The EPA received only supportive comments regarding these amendments. See the document Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule in Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.</P>
                    <HD SOURCE="HD1">V. Other Final Minor Revisions or Clarifications</HD>
                    <P>See table 3 of this preamble for the miscellaneous minor technical corrections not previously described in this preamble that we are finalizing throughout subpart W, consistent with section II.D. of this preamble.  </P>
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                    <BILCOD>BILLING CODE 6560-50-C</BILCOD>
                    <HD SOURCE="HD1">IV. Effective Date of the Final Amendments</HD>
                    <P>
                        The EPA is finalizing the effective date of the amendments with some updates from proposal, that will phase in the final amendments. The effective dates listed in the 
                        <E T="02">DATES</E>
                         section of this preamble reflect when the amendments will be published in the CFR. As described in more detail in section IV.A. of this preamble, we are finalizing that the majority of the final amendments will become effective on January 1, 2025, as proposed, and that reporters will implement all but a few of those changes beginning with reports prepared for RY2025 and submitted by March 31, 2026. The submission date for RY2025 reports is over a year after the finalization of this rule, thus providing a reasonable period for reporters to adjust to any final amendments that require a change to data collection, calculation methods, or reporting. The requirements that will become effective on January 1, 2025, and must be implemented beginning with reports prepared for RY2024 and submitted by March 31, 2025 are reporting requirements that do not require additional data collection or calculations. In addition, as described in more detail in section IV.B. of this preamble, the EPA is finalizing that certain optional additional calculation methods and other provisions that allow owners and operators of applicable facilities to submit empirical emissions data, consistent with CAA section 136(h), will become effective on July 15, 2024. This earlier effective date will allow reporters the option to elect to use those methods for RY2024. Specific information regarding what provisions are allowed or required each year is provided in sections IV.A. and IV.B. of this preamble.
                    </P>
                    <P>We are also finalizing that the CBI determinations for new and substantially revised data elements discussed in section V. of this preamble become effective on the same date that the new data element or final revisions to existing data elements become effective. The exception is one circumstance, discussed in detail in section V. of this preamble, where the final determination covers data included in annual GHG reports submitted for prior years. In all cases, as proposed, the final determination for the data that the EPA has already received for these prior years or receives going forward for any reporting year would become effective on January 1, 2025.</P>
                    <HD SOURCE="HD2">A. Amendments That Are Effective on January 1, 2025</HD>
                    <P>Table 4 of this preamble lists the affected subparts, the final revisions that are effective on January 1, 2025, and the RY report in which those changes will first be reflected. January 1, 2025, is the effective date, which is the date that the CFR regulatory text is revised to reflect those changes. However, the report in which that amendment will first be reflected is either RY2024 or RY2025, depending upon the substance of that change (i.e., what that change requires the reporter to do to comply with it).</P>
                    <P>Changes with effective date January 1, 2025, that must be reflected starting with the RY2024 report are those that require no changes to be made by reporters during the reporting year and thus provide reporters a reasonable time to adjust to these certain final amendments prior to submission of the RY2024 report. These are also reporting elements necessary for implementation of WEC. Specifically, the final reporting of the quantities of natural gas and crude oil produced that is sent to sale in the calendar year for each well permanently shut-in and plugged (40 CFR 98.236(aa)(1)(iii)(C) and (D) and 40 CFR 98.236(aa)(2)(iii) and (iv)) become effective on January 1, 2025 and reporters must, as applicable, include that information in their reports prepared for RY2024 and submitted March 31, 2025.</P>
                    <P>
                        Changes with effective date January 1, 2025 that must be reflected starting with the RY2025 reports include requirements to begin reporting emissions for new emission sources, both those that are being added to subpart W for the first time in this final rule (
                        <E T="03">e.g.</E>
                        , other large release events, crankcase venting) and those that expand the applicability of reporting for emission source types in subpart W to additional industry segments, as described in section III.C.1. of this preamble, as well as requirements to begin accounting for additional emission points from existing emission source types (
                        <E T="03">e.g.</E>
                        , methane slip from combustion equipment). They also include changes that affect monitoring or data collection requirements, such as requirements for certain simulation inputs for AGRs, dehydrators, and atmospheric storage tanks to be based on measurement, and changes to required calculation methodologies, such as determination of the flow rate and composition of gas routed to a flare if continuous monitors are not present.
                    </P>
                    <GPH SPAN="3" DEEP="250">
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                    </GPH>
                    <HD SOURCE="HD2">B. Amendments That Are Effective July 15, 2024</HD>
                    <P>Table 5 of this preamble lists the final amendments that are effective July 15, 2024, all of which may be reflected in the RY2024 report for the first time if elected by the reporter. These amendments include optional additional calculation methods and other provisions that allow owners and operators of applicable facilities to submit empirical emissions data, consistent with CAA section 136(h). This earlier effective date will allow reporters the option to elect to use those methods for RY2024. The amendments to calculation methodologies that are effective July 15, 2024 for various emission source types specify that reporters may use data collected anytime during the calendar year for any of the applicable calculation methods, provided that the data were collected in accordance with and meet the criteria of the applicable paragraphs. For example, if a reporter installed a continuous flow meter that is capable of meeting the requirements of 40 CFR 98.234(b) on the natural gas supply line dedicated to any one or combination of natural gas pneumatic devices prior to January 1, 2024, the reporter may use Calculation Method 1 for natural gas pneumatic devices for all of RY2024, not just the period between July 15, 2024 and December 31, 2024.</P>
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                    <BILCOD>BILLING CODE 6560-50-C</BILCOD>
                    <HD SOURCE="HD1">V. Final Confidentiality and Reporting Determinations for Certain Data Reporting Elements</HD>
                    <P>This section provides a summary of the EPA's final confidentiality determinations and emission data designations for new and substantially revised data elements included in these final amendments, certain existing part 98 data elements for which no determination has been previously established, certain existing part 98 data elements for which the EPA is amending or clarifying the existing confidentiality determination, and the EPA's final reporting determinations for inputs to equations included in the final amendments. This section also identifies any changes to the proposed confidentiality determinations, emissions data designations, or reporting determinations in the final rule. Finally, this section summarizes the major comments and responses related to the proposed confidentiality determinations, emission data designations, and reporting determinations for these data elements.</P>
                    <HD SOURCE="HD2">A. EPA's Approach To Assess Data Elements</HD>
                    <P>
                        In the 2023 Subpart W Proposal, the EPA proposed to assess data elements for eligibility of confidential treatment using a revised approach, in response to 
                        <E T="03">Food Marketing Institute</E>
                         v. 
                        <E T="03">Argus Leader Media</E>
                        , 139 S. Ct. 2356 (2019) (hereafter referred to as 
                        <E T="03">Argus Leader</E>
                        ).
                        <SU>87</SU>
                        <FTREF/>
                         The EPA proposed that the 
                        <E T="03">Argus Leader</E>
                         decision did not affect our approach to designating data elements as “inputs to emission equations” or our previous approach for designating new and revised reporting requirements as “emission data.” We proposed to continue identifying new and revised reporting elements that qualify as “emission data” (
                        <E T="03">i.e.,</E>
                         data necessary to determine the identity, amount, frequency, or concentration of the emission emitted by the reporting facilities) by evaluating the data for assignment to one of the four data categories designated by the 2011 Final CBI Rule (76 FR 30782, May 26, 2011) to meet the CAA definition of “emission data” in 40 CFR 2.301(a)(2)(i) (hereafter referred to as “emission data categories”). Refer to section II.B. of the July 7, 2010 proposal (75 FR 39094) for descriptions of each of these data categories and the EPA's rationale for designating each data category as “emission data.” For data elements designated as “inputs to emission equations,” the EPA maintained the two subcategories, data elements entered into e-GGRT's Inputs Verification Tool (IVT) and those directly reported to the EPA. Refer to section V.C. of the preamble to the 2023 Subpart W Proposal for further discussion of “inputs to emission equations.”
                    </P>
                    <FTNT>
                        <P>
                            <SU>87</SU>
                             Available in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).
                        </P>
                    </FTNT>
                    <P>
                        In the 2023 Subpart W Proposal, for new or revised data elements that the EPA did not propose to designate as “emission data” or “inputs to emission equations,” the EPA proposed a revised approach for assessing data confidentiality. We proposed to assess each individual reporting element according to the new 
                        <E T="03">Argus Leader</E>
                         standard. So, we evaluated each data element individually to determine whether the information is customarily and actually treated as private by the reporter and proposed a confidentiality determination based on that evaluation.
                    </P>
                    <P>
                        The EPA received several comments on its proposed approach in the 2023 Subpart W Proposal. The commenters' concerns and the EPA's responses thereto are provided in the document Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule in Docket ID. No. EPA-HQ-OAR-2023-0234. Following consideration of the comments received, the EPA is not revising this approach and is continuing to assess data elements for confidentiality determinations as described in the 2023 Subpart W Proposal. We are also finalizing the specific confidentiality determinations and reporting determinations as 
                        <PRTPAGE P="42200"/>
                        described in sections V.B. and V.C. of this preamble.
                    </P>
                    <HD SOURCE="HD2">B. Final Confidentiality Determinations and Emissions Data Designations</HD>
                    <HD SOURCE="HD3">1. Final Confidentiality Determinations for New and Revised Data Elements</HD>
                    <P>The EPA is making final confidentiality determinations and emission data designations for new and substantially revised data elements included in these final amendments. Substantially revised data elements include those data elements where the EPA is, in this final action, substantially revising the data elements as compared to the existing requirements. Please refer to the preamble to the 2023 Subpart W Proposal for additional information regarding the proposed confidentiality determinations for these data elements.</P>
                    <P>
                        The EPA is not finalizing the proposed confidentiality determinations for certain data elements in subpart W because the EPA is not taking final action on the requirements to report these data elements at this time (see section III. of this preamble for additional information). These data elements are listed in Table 4 of the memorandum, 
                        <E T="03">Confidentiality Determinations and Emission Data Designations for Data Elements in the 2024 Final Revisions to the Greenhouse Gas Reporting Rule for Petroleum and Natural Gas Systems,</E>
                         available in the docket to this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                    </P>
                    <P>For one data element, the EPA proposed a confidentiality determination in the 2023 Subpart W Proposal but is not finalizing a confidentiality determination at this time. In the 2023 Subpart W Proposal, the EPA proposed a confidentiality determination of “Eligible for Confidential Treatment” for 40 CFR 98.236(aa)(3)(ix), the quantity of residue gas leaving that has been processed by the facility and any gas that passes through the facility to sale without being processed by the facility in the calendar year. In the 2024 WEC Proposal, the EPA re-proposed the confidentiality status for this data element as “No Determination.” We intend to consider comments submitted on the 2024 WEC rulemaking on this proposed confidentiality status before finalizing a confidentiality determination for this data element through rulemaking. We intend to make this determination along a similar timeline as the final WEC rule.</P>
                    <P>
                        In some cases, the EPA is finalizing revisions from the proposed rule that include new data elements for which the EPA did not propose a confidentiality determination. These data elements are listed in table 6 of this preamble and Table 5 of the memorandum, 
                        <E T="03">Confidentiality Determinations and Emission Data Designations for Data Elements in the 2024 Final Revisions to the Greenhouse Gas Reporting Rule for Petroleum and Natural Gas Systems,</E>
                         available in the docket to this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234. Because these data elements were not included in the proposal, the EPA was unable to solicit public comment on confidentiality determinations for these data elements. Accordingly, we are not finalizing confidentiality determinations for any of these data elements at this time.
                    </P>
                    <BILCOD>BILLING CODE 6560-50-P</BILCOD>
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                    </GPH>
                    <GPH SPAN="3" DEEP="640">
                        <PRTPAGE P="42202"/>
                        <GID>ER14MY24.014</GID>
                    </GPH>
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                    </GPH>
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                    </GPH>
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                    </GPH>
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                        <PRTPAGE P="42206"/>
                        <GID>ER14MY24.018</GID>
                    </GPH>
                    <GPH SPAN="3" DEEP="640">
                        <PRTPAGE P="42207"/>
                        <GID>ER14MY24.019</GID>
                    </GPH>
                    <GPH SPAN="3" DEEP="281">
                        <PRTPAGE P="42208"/>
                        <GID>ER14MY24.020</GID>
                    </GPH>
                    <BILCOD>BILLING CODE 6560-50-C</BILCOD>
                    <P>
                        In a handful of cases, the EPA has made minor revisions to data elements in this final action as compared to the proposed data element included in the 2023 Subpart W Proposal. For certain proposed data elements, we have revised the citations from proposal to final. In other cases, the minor revisions include clarifications to the text. The EPA evaluated these data elements and how they have been clarified in the final rule to verify that the information collected has not substantially changed since proposal. These data elements are listed in Table 6 of the memorandum, 
                        <E T="03">Confidentiality Determinations and Emission Data Designations for Data Elements in the 2024 Final Revisions to the Greenhouse Gas Reporting Rule for Petroleum and Natural Gas Systems,</E>
                         available in the docket to this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234. Because the information to be collected has not substantially changed in a way that would affect the confidential nature of the information to be collected from the proposal, we are finalizing the confidentiality determinations or emission data designations for these data elements as proposed. For additional information on the rationales for the confidentiality determinations for these data elements, see the preamble to the 2023 Subpart W Proposal and the memorandum, 
                        <E T="03">Proposed Confidentiality Determinations and Emission Data Designations for Data Elements in Proposed Revisions to the Greenhouse Gas Reporting Rule for Petroleum and Natural Gas Systems,</E>
                         available in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).
                    </P>
                    <P>For all other confidentiality determinations for the new or substantially revised data reporting elements for these subparts, the EPA is finalizing the confidentiality determinations as they were proposed. Please refer to the preamble to the 2023 Subpart W Proposal for additional information regarding these confidentiality determinations.</P>
                    <HD SOURCE="HD3">2. Final Confidentiality Determinations and Emission Data Designations for Existing Data Elements for Which the EPA Did Not Previously Finalize a Confidentiality Determination or Emission Data Designation</HD>
                    <P>The EPA is finalizing the confidentiality determination as it was proposed for the one subpart W data reporting element for which no determination has been previously established. The EPA received no comments on the proposed determination. Please refer to the preamble to the 2023 Subpart W Proposal for additional information regarding the proposed confidentiality determination.</P>
                    <HD SOURCE="HD2">C. Final Reporting Determinations for Inputs to Emissions Equations</HD>
                    <P>In the 2023 Subpart W Proposal, the EPA proposed to assign several data elements to the “Inputs to Emission Equation” data category. As discussed in section VI.B.1. of the 2022 Proposed Rule (87 FR 36920, June 21, 2022), the EPA determined that the Argus Leader decision does not affect our approach for handling of data elements assigned to the “Inputs to Emission Equations” data category. Data assigned to the “Inputs to Emission Equations” data category are assigned to one of two subcategories, including “inputs to emission equations” that must be directly reported to the EPA, and “inputs to emission equations” that are not reported but are entered into the EPA's IVT. The EPA received no comments specific to the proposed reporting determinations for inputs to emission equations in the proposed rules. Additional information regarding these reporting determinations may be found in section V.C. of the preamble to the 2023 Subpart W Proposal.</P>
                    <P>
                        The EPA is not finalizing the proposed reporting determinations for certain data elements in subpart W because the EPA is not taking final action on the requirements to report these data elements at this time (see section III. of this preamble for additional information). These data elements are listed in Table 2 of the memorandum, 
                        <E T="03">
                            Reporting 
                            <PRTPAGE P="42209"/>
                            Determinations for Data Elements Assigned to the Inputs to Emission Equations Data Category in the 2024 Final Revisions to the Greenhouse Gas Reporting Rule for Petroleum and Natural Gas Systems
                        </E>
                        , available in the docket to this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                    </P>
                    <P>
                        In some cases, the EPA is finalizing revisions that include new data elements that the EPA did not propose to assign to the “Inputs to Emission Equations” data category. These data elements are listed in Table 3 of the memorandum, 
                        <E T="03">Reporting Determinations for Data Elements Assigned to the Inputs to Emission Equations Data Category in the 2024 Final Revisions to the Greenhouse Gas Reporting Rule for Petroleum and Natural Gas Systems</E>
                        , available in the docket to this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234. Because the EPA has not proposed or solicited public comment on an inputs determination for these data elements, we are not finalizing reporting determinations for these data elements at this time.
                    </P>
                    <P>
                        In a handful of cases, the EPA has made minor revisions to data elements assigned to the “Inputs to Emissions Equations” category in this final action as compared to the proposed data element included in the 2023 Subpart W Proposal. For certain proposed data elements, we have revised the citations from proposal to final. In other cases, the minor revisions include clarifications to the text. The EPA evaluated these inputs to emissions equations and how they have been clarified in the final rule to verify that the data element has not substantially changed since proposal. These data elements and how they have been clarified in the final rule are listed in Table 4 of the memorandum, 
                        <E T="03">Reporting Determinations for Data Elements Assigned to the Inputs to Emission Equations Data Category in the 2024 Final Revisions to the Greenhouse Gas Reporting Rule for Petroleum and Natural Gas Systems</E>
                        , available in the docket to this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234. Because the input has not substantially changed since proposal, we are finalizing the proposed reporting determinations for these data elements as proposed. For additional information on the rationale for the reporting determinations for the data elements, see the preamble to the 2023 Subpart W Proposal and the memorandum 
                        <E T="03">Proposed Reporting Determinations for Data Elements Assigned to the Inputs to Emission Equations Data Category in Proposed Revisions to the Greenhouse Gas Reporting Rule for Petroleum and Natural Gas Systems</E>
                        , available in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).
                    </P>
                    <P>For all other reporting determinations for the data elements assigned to the “Inputs to Emission Equations” data category, the EPA is finalizing the reporting determinations as they were proposed. Please refer to the preamble to the 2023 Subpart W Proposal for additional information.</P>
                    <HD SOURCE="HD1">VI. Impacts of the Final Amendments</HD>
                    <P>This section summarizes the impacts related to the specific substantive final amendments for subpart W (as well as subparts A and C), as generally described in section II. of this preamble. Major changes to the impacts analysis for the final rule as compared to the impacts analysis for the proposed revisions are identified in this section. Total costs have increased from $92.3 million per year at proposal to $183.6 million per year at final due to underestimates at proposal in the labor hours needed to comply with these amendments. As described in section II. of this preamble, for some proposed revisions, we are not taking final action on revisions to calculation, monitoring, or reporting requirements that would have required reporters to collect or submit additional data. Therefore, the final burden for these sources have been revised to reflect only those requirements that are being finalized. For example, as discussed in section II.N. of this preamble, the proposed revision to require continuous parameter monitoring for flares is not being finalized, resulting in the reduction of capital costs by $19.1 million as compared to the proposal's cost analysis.</P>
                    <P>
                        The EPA also received a number of comments on the proposed revisions and the impacts of the proposed revisions. Following consideration of these comments, the EPA has, in some cases, revised the final rule requirements and updated the impacts analysis to reflect these changes. The summary of the final amendments impacts is followed by a summary of the major comments on the proposed amendments impacts and the EPA's responses to those comments. The document 
                        <E T="03">Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems under the Greenhouse Gas Reporting Rule</E>
                        , available in the docket to this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234), contains the full text of all the comments on impacts of the 2023 Subpart W Proposal, including the major comments responded to in this preamble.
                    </P>
                    <HD SOURCE="HD2">A. Cost Analysis</HD>
                    <HD SOURCE="HD3">1. Summary of Cost Analysis for Final Amendments</HD>
                    <P>
                        The revisions will amend requirements that apply to the petroleum and natural gas systems source category of the Greenhouse Gas Reporting Rule consistent with CAA section 136(h) to ensure that reporting under subpart W is based on empirical data and accurately reflects total CH
                        <E T="52">4</E>
                         emissions and waste emissions from applicable facilities, and to allow owners and operators of applicable facilities to submit empirical emissions data that appropriately could demonstrate the extent to which a charge is owed in future implementation of CAA section 136. These revisions include improving the existing calculation, recordkeeping, and reporting requirements. Note that one proposed revision to require continuous parameter monitoring for flares is not being finalized, resulting in the reduction of capital costs by $19.1 million.
                    </P>
                    <P>The EPA is finalizing amendments to part 98 in order to implement improvements to the GHGRP, including revisions to update existing emission factors and emissions estimation methodologies, revisions to require reporting of additional data for new emission sources and address potential gaps in reporting, and revisions to collect data that will improve the EPA's understanding of the sector-specific processes or other factors that influence GHG emission rates, verification of collected data, or to complement or inform other EPA programs. The EPA is also finalizing revisions that will improve implementation of the program, such as those that will provide flexibility for or simplifying calculation and monitoring methodologies, streamline recordkeeping and reporting, and other minor technical corrections or clarifications identified as a result of working with the affected sources during rule implementation and outreach. The EPA anticipates that the revisions to improve accuracy of reporting will increase costs for reporters.</P>
                    <P>
                        As discussed in section V. of this preamble, we are implementing some of these provisions beginning in RY2024 and some beginning in RY2025. The amendments for requirements for which reporters would incur costs will be effective beginning in RY2025. Costs have been estimated over the three years 
                        <PRTPAGE P="42210"/>
                        following the year of implementation. The incremental implementation costs for each reporting year are summarized in table 7 of this preamble. The estimated annual average labor burden is $169.4 million per year and the annual average labor burden per reporter is $55,100. The incremental burden for subpart W and the incremental costs per reporter are shown in table 7 of this preamble.
                    </P>
                    <GPOTABLE COLS="5" OPTS="L2,i1" CDEF="s100,r65,r65,r65,r65">
                        <TTITLE>Table 7—Total Incremental Labor Burden for Reporting Years 2025-2027</TTITLE>
                        <TDESC>[$2021/year]</TDESC>
                        <BOXHD>
                            <CHED H="1">Cost summary</CHED>
                            <CHED H="1">RY2025</CHED>
                            <CHED H="1">RY2026</CHED>
                            <CHED H="1">RY2027</CHED>
                            <CHED H="1">
                                Annual
                                <LI>average</LI>
                            </CHED>
                        </BOXHD>
                        <ROW>
                            <ENT I="01">Burden by Year</ENT>
                            <ENT>$169.4 million</ENT>
                            <ENT>$169.4 million</ENT>
                            <ENT>$169.4 million</ENT>
                            <ENT>$169.4 million.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Number of Reporters</ENT>
                            <ENT>3,077</ENT>
                            <ENT>3,077</ENT>
                            <ENT>3,077</ENT>
                            <ENT>3,077.</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Incremental Labor Cost per Reporter</ENT>
                            <ENT>$55,100</ENT>
                            <ENT>$55,100</ENT>
                            <ENT>$55,100</ENT>
                            <ENT>$55,100.</ENT>
                        </ROW>
                    </GPOTABLE>
                    <P>There is an additional annualized incremental burden of $14.1 million for operation and maintenance (O&amp;M) costs, which reflects changes to applicability and monitoring. Including capital and O&amp;M costs, the total annual average burden is $183.6 million over the next 3 years.</P>
                    <P>The total incremental burden and burden by reporter per subpart W industry segment are shown in table 8 of this preamble.</P>
                    <GPOTABLE COLS="6" OPTS="L2,p7,7/8,i1" CDEF="s50,10,12,12,12,12">
                        <TTITLE>Table 8—Total Incremental Burden by Industry Segment and by Reporter</TTITLE>
                        <TDESC>
                            [$2021/year] 
                            <SU>a</SU>
                        </TDESC>
                        <BOXHD>
                            <CHED H="1">Industry segment</CHED>
                            <CHED H="1">
                                Count of
                                <LI>
                                    reporters 
                                    <SU>b</SU>
                                </LI>
                            </CHED>
                            <CHED H="1">
                                Labor costs 
                                <SU>c</SU>
                            </CHED>
                            <CHED H="1">
                                Capital and
                                <LI>O&amp;M</LI>
                                <LI>(annualized)</LI>
                            </CHED>
                            <CHED H="1">
                                Total
                                <LI>annual cost</LI>
                            </CHED>
                            <CHED H="1">
                                Total
                                <LI>annual</LI>
                                <LI>cost per</LI>
                                <LI>reporter</LI>
                            </CHED>
                        </BOXHD>
                        <ROW>
                            <ENT I="01">Onshore Petroleum and Natural Gas Production</ENT>
                            <ENT>777</ENT>
                            <ENT>$142,067,784</ENT>
                            <ENT>$3,693,563</ENT>
                            <ENT>$145,761,348</ENT>
                            <ENT>$187,595</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Offshore Petroleum and Natural Gas Production</ENT>
                            <ENT>141</ENT>
                            <ENT>3,922</ENT>
                            <ENT>0</ENT>
                            <ENT>3,922</ENT>
                            <ENT>28</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Onshore Petroleum and Natural Gas Gathering and Boosting</ENT>
                            <ENT>361</ENT>
                            <ENT>10,767,359</ENT>
                            <ENT>1,319,919</ENT>
                            <ENT>12,087,278</ENT>
                            <ENT>33,483</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Onshore Natural Gas Processing</ENT>
                            <ENT>515</ENT>
                            <ENT>11,873,365</ENT>
                            <ENT>2,776,745</ENT>
                            <ENT>14,650,110</ENT>
                            <ENT>28,447</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Onshore Natural Gas Transmission Compression</ENT>
                            <ENT>1,008</ENT>
                            <ENT>4,064,345</ENT>
                            <ENT>5,891,787</ENT>
                            <ENT>9,956,131</ENT>
                            <ENT>9,877</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Natural Gas Transmission Pipeline</ENT>
                            <ENT>53</ENT>
                            <ENT>89,867</ENT>
                            <ENT>187</ENT>
                            <ENT>90,054</ENT>
                            <ENT>1,699</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Underground Natural Gas Storage</ENT>
                            <ENT>68</ENT>
                            <ENT>319,173</ENT>
                            <ENT>370,275</ENT>
                            <ENT>689,448</ENT>
                            <ENT>10,139</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">LNG Import and Export Equipment</ENT>
                            <ENT>11</ENT>
                            <ENT>51,729</ENT>
                            <ENT>26,350</ENT>
                            <ENT>78,079</ENT>
                            <ENT>7,098</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">LNG Storage</ENT>
                            <ENT>7</ENT>
                            <ENT>29,922</ENT>
                            <ENT>24,890</ENT>
                            <ENT>54,812</ENT>
                            <ENT>7,830</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Natural Gas Distribution</ENT>
                            <ENT>164</ENT>
                            <ENT>179,491</ENT>
                            <ENT>0</ENT>
                            <ENT>179,491</ENT>
                            <ENT>1,094</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Petroleum and Natural Gas Systems (all segments)</ENT>
                            <ENT>3,077</ENT>
                            <ENT>169,446,957</ENT>
                            <ENT>14,103,716</ENT>
                            <ENT>183,550,673</ENT>
                            <ENT>59,652</ENT>
                        </ROW>
                        <TNOTE>
                            <SU>a</SU>
                             Includes estimated increase in costs following implementation of revisions in RY2025.
                        </TNOTE>
                        <TNOTE>
                            <SU>b</SU>
                             Counts are based on GHGRP data reported in RY2020 and 567 new facilities, as detailed in the memorandum, 
                            <E T="03">Assessment of Burden Impacts for Greenhouse Gas Reporting Rule Revisions for Petroleum and Natural Gas Systems.</E>
                        </TNOTE>
                        <TNOTE>
                            <SU>c</SU>
                             Initial year and subsequent year labor costs are $169.4 million per year.
                        </TNOTE>
                    </GPOTABLE>
                    <P>
                        A full discussion of the cost and burden impacts may be found in the memorandum, 
                        <E T="03">Assessment of Burden Impacts for Greenhouse Gas Reporting Rule Revisions for Petroleum and Natural Gas Systems</E>
                        , available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234. As described further in section VI.B. of this preamble, the national total annual costs of the final rule reflect the fact that there are a large number of affected entities, but per entity costs and impacts are low. Considering the improvements to the GHGRP contained in this final rule as well as the need to comply with CAA section 136(h) and the anticipated costs of this rule in the context of this industry, the EPA concludes that the anticipated costs are reasonable and support the final rule.
                    </P>
                    <HD SOURCE="HD3">2. Summary of Comments and Responses</HD>
                    <P>This section summarizes the major comments and responses related to the proposed cost impacts.</P>
                    <P>
                        <E T="03">Comment:</E>
                         Multiple commenters disagreed with the cost estimates related to changing the reporting of total emissions at the basin level to reporting total emissions at the well-pad level (for Onshore Petroleum and Natural Gas Production) or gathering and boosting site level (for Onshore Petroleum and Natural Gas Gathering and Boosting). The commenters estimated costs that were 8 times higher than the EPA's costs for Onshore Petroleum and Natural Gas Production reporting and 15 times higher than the EPA's costs for Onshore Petroleum and Natural Gas Gathering and Boosting reporting.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         Based on consideration of the commenter's cost analysis, the EPA reassessed the costs for these proposed changes. After consideration of the large amount of administrative burden shown by the commenters, the EPA determined it was appropriate to increase the estimated level of burden and associated costs. The relevant cost analysis in the proposal was based only on the number of facilities, without taking into consideration the number of wells per well-pad per Onshore Petroleum and Natural Gas Production facility and the number of sites per Onshore Petroleum and Natural Gas Gathering and Boosting facility. The labor hours were increased from 15 hours at proposal to 90 hours at final for the Onshore Petroleum and Natural Gas Production industry segment and from 5 hours at proposal to 45 hours at final for the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment. As a result, in the EPA's final amendments cost analysis, these costs have increased from $1.0 million total for both industry segments in the proposal to $6.5 million total for both industry segments. For more information, see the information collection request (ICR) document OMB No. 2060-0751 (EPA ICR number 2774.02) and 
                        <E T="03">Assessment of Burden Impacts for Greenhouse Gas Reporting Rule Revisions for Petroleum and Natural Gas Systems.</E>
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter noted that the cost analyses related to the 
                        <PRTPAGE P="42211"/>
                        determination of fuel consumption through fuel records in order to incorporate combustion slip into their emissions was underestimated. The commenter argued that the costs should be based on the number of well-pads or sites instead of the number of facilities and that the level of effort should be increased from 30 minutes to one hour.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         The costs analysis relevant here in the proposal was based only on the number of facilities, without taking into consideration the number of wells per well-pad per Onshore Petroleum and Natural Gas Production facility and the number of sites per Onshore Petroleum and Natural Gas Gathering and Boosting facility. In the EPA's final amendments cost analysis, these costs have increased from $50,000 total for both industry segments to $9.2 million total for the three applicable industry segments. Costs were updated based on the number of well-pads or sites instead of the number of facilities and the labor estimate was increased from 30 minutes per facility to one hour per well-pad or site for the Onshore Petroleum and Natural Gas Production industry segment and the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment. The labor estimate was increased from 30 minutes per facility to one hour per facility for the Natural Gas Distribution industry segment. In the final impacts analysis we also changed the characterization of combustion slip from a new emission source to a change in requirements. For more information, see ICR document OMB No. 2060-0751 (EPA ICR number 2774.02) and 
                        <E T="03">Assessment of Burden Impacts for Greenhouse Gas Reporting Rule Revisions for Petroleum and Natural Gas Systems.</E>
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter noted that the cost analyses related to the proposed revisions to 40 CFR 98.36(c)(1) and (3) did not include burden for the industry segments that have previously reported their combustion emissions to subpart C. The commenter stated that the proposed revisions clarify that reporters must separately report equipment type within the same aggregation of units or common pipe configuration. According to the commenter, there is significant burden to change from the aggregation/common pipe methods in subpart C to the methods within subpart W. The commenter stated that the costs should be at least 2 hours per year per each aggregation of units/common pipe reported under subpart C.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         As noted by the commenter, costs for this revision were inadvertently excluded from the impacts analysis in the proposal. After review of commenter's suggestions, the costs have been incorporated using the suggested burden, and we included the average number of aggregations reported to Subpart C for each of the five affected industry segments (Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, LNG Import and Export Equipment, and LNG Storage). Costs were calculated assuming 10 hours per facility per year, or 2 hours per aggregation of units/common pipe reported under subpart C and an average of five aggregations per facility based on subpart C data. In the EPA's final amendments cost analysis, these costs have increased to $1.7 million total for the five affected industry segments. For more information, see ICR document OMB No. 2060-0751 (EPA ICR number 2774.02) and 
                        <E T="03">Assessment of Burden Impacts for Greenhouse Gas Reporting Rule Revisions for Petroleum and Natural Gas Systems.</E>
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         Two commenters noted that the cost analyses related to the proposed revisions to 40 CFR 98.233(n)(2) did not include burden to account for the monthly visual inspections required for flares that are not equipped with continuous pilot light monitoring.
                    </P>
                    <P>
                        <E T="03">Response:</E>
                         As noted by the commenter, costs for this revision were inadvertently excluded from the impacts analysis in the proposal. After review of commenter's suggestions, the costs have been incorporated. Assuming that a technician will inspect each flare once per month, costs have been updated to $870,000 for Onshore Natural Gas Processing, $23,000 for Onshore Natural Gas Transmission Compression, $25,000 for Underground Natural Gas Storage, $31,000 for LNG Import and Export Equipment, $4.9 million for Onshore Petroleum and Natural Gas Gathering and Boosting, and $53.5 million for Onshore Petroleum and Natural Gas Production. Overall costs increased by $59.4 million from proposal to final.
                    </P>
                    <P>
                        For more information, see ICR document OMB No. 2060-0751 (EPA ICR number 2774.02) and 
                        <E T="03">Assessment of Burden Impacts for Greenhouse Gas Reporting Rule Revisions for Petroleum and Natural Gas Systems.</E>
                    </P>
                    <P>
                        <E T="03">Comment:</E>
                         One commenter noted that the cost analyses related to the requirement to inspect dump valves was based on the number of malfunctioning dump valves in each industry segment instead of the number of tanks in each industry segment.
                    </P>
                    <P>A second commenter noted that malfunctioning dump valves on atmospheric storage tanks were incorrectly categorized as new emission sources even though dump valves are currently reported under the GHGRP with different requirements.</P>
                    <P>
                        <E T="03">Response:</E>
                         As noted by the commenter, costs for this revision were inadvertently based on the number of malfunctioning dump valves in one reporting year instead of the number of dump valves that must be inspected. Changes were made to the costs related to dump valve inspections, assuming one dump valve per tank and using the count of tanks for each industry segment. Costs in the final rule impacts analysis are $4.2 million for Onshore Petroleum and Natural Gas Production, $650,000 for Onshore Petroleum and Natural Gas Gathering and Boosting and $920,000 for Onshore Natural Gas Processing. The overall costs increased by $5.7 million from proposal to final.
                    </P>
                    <P>
                        For more information, see ICR document OMB No. 2060-0751 (EPA ICR number 2774.02) and 
                        <E T="03">Assessment of Burden Impacts for Greenhouse Gas Reporting Rule Revisions for Petroleum and Natural Gas Systems.</E>
                    </P>
                    <P>In response to the second commenter, the final impacts analysis changed the characterization of malfunctioning dump valves from a new emission source to a change in requirements.</P>
                    <HD SOURCE="HD2">B. Cost-to-Revenue Ratio Analysis</HD>
                    <P>
                        To further assess the economic impacts of the final rule, the EPA revised from proposal its screening analysis comparing the estimated total annualized compliance costs for the petroleum and natural gas systems industry segments with industry mean cost-to-revenue ratios based on the total facility costs that are applicable to parent entities in each segment in the final rule. This analysis shows that the per-entity impacts within each industry segment are low. These low mean cost-to-revenue ratios indicate that the final rule is unlikely to result in significant changes in parent entity production decisions or other choices that would result in significant fluctuations in prices or quantities in affected markets.
                        <PRTPAGE P="42212"/>
                    </P>
                    <GPOTABLE COLS="2" OPTS="L2,i1" CDEF="s100,20">
                        <TTITLE>Table 9—Mean CRRs for Parent Entities by Industry Segment, All Business Sizes</TTITLE>
                        <BOXHD>
                            <CHED H="1">Industry segment</CHED>
                            <CHED H="1">
                                Mean CRR
                                <LI>(standard error)</LI>
                            </CHED>
                        </BOXHD>
                        <ROW>
                            <ENT I="01">Onshore petroleum and natural gas production</ENT>
                            <ENT>1.71% (1.63-1.80%)</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Offshore petroleum and natural gas production</ENT>
                            <ENT>0.02% (0.01-0.02%)</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Onshore petroleum and natural gas gathering and boosting</ENT>
                            <ENT>0.90% (0.82-0.99%)</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Onshore natural gas processing</ENT>
                            <ENT>0.71% (0.61-0.81%)</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Onshore natural gas transmission compression</ENT>
                            <ENT>0.39% (0.30-0.48%)</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Onshore natural gas transmission pipeline</ENT>
                            <ENT>0.36% (0.22-0.49%)</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Underground natural gas storage</ENT>
                            <ENT>0.01% (0.01-0.01%)</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">LNG import and export equipment</ENT>
                            <ENT>0.02% (0.01-0.03%)</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">LNG storage</ENT>
                            <ENT>0.00% (0.00-0.00%)</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Natural gas distribution</ENT>
                            <ENT>0.17% (0.11-0.23%)</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">All segments</ENT>
                            <ENT>1.05% (1.00-1.10%)</ENT>
                        </ROW>
                        <TNOTE>CRR = cost-to-revenue ratio.</TNOTE>
                    </GPOTABLE>
                    <P>The EPA also evaluated the mean costs to individual facilities and mean costs to parents (accounting for multiple owned facilities) for reporters (shown in table 10 of this preamble), which are relatively small given the high revenues of parent companies within the petroleum and natural gas systems sector. There are currently 2,322 existing facilities reporting to subpart W that are owned by approximately 600 parent entities. Based on a review of revenue data available for approximately 587 parent entities, the final rule costs represent less than one percent of the total annual revenue for parent entities that would be reporting under subpart W.</P>
                    <GPOTABLE COLS="2" OPTS="L2,i1" CDEF="s100,25">
                        <TTITLE>Table 10—Estimated Mean Costs and Revenues for Facility and Parent Entities, All Segments</TTITLE>
                        <BOXHD>
                            <CHED H="1">Metric</CHED>
                            <CHED H="1">
                                Estimated values
                                <LI>(95% confidence interval)</LI>
                            </CHED>
                        </BOXHD>
                        <ROW>
                            <ENT I="01">
                                Mean cost to parent entity per facility (thousands) 
                                <SU>a</SU>
                            </ENT>
                            <ENT>$43.1 ($42.8-$43.3)</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Mean number of facilities owned per parent</ENT>
                            <ENT>4.6</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">
                                Mean cost to parent for all associated facilities (thousands) 
                                <SU>a</SU>
                            </ENT>
                            <ENT>$201.8 ($196.1-$207.5)</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">
                                Mean parent entity revenue (billions) 
                                <SU>a</SU>
                            </ENT>
                            <ENT>$11.70 ($10.90-$12.50)</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">Total revenue for all subpart W parents (trillions)</ENT>
                            <ENT>$8.82 ($8.22-$9.42)</ENT>
                        </ROW>
                        <ROW>
                            <ENT I="01">
                                Mean CRR for parent entities, using all facility costs 
                                <SU>b</SU>
                            </ENT>
                            <ENT>1.05% (1.00-1.10%)</ENT>
                        </ROW>
                        <TNOTE>
                            <SU>a</SU>
                             Average across all existing and new reporters.
                        </TNOTE>
                        <TNOTE>
                            <SU>b</SU>
                             Because parent revenues are heavily skewed towards higher revenues, the ratio of mean cost to mean revenue (which is approximately 0.0004%) differs substantially from the mean cost-to-revenue ratio (which is approximately 1.05%).
                        </TNOTE>
                    </GPOTABLE>
                    <P>
                        The EPA has also assessed the potential benefits of the final amendments to subpart W. The implementation of the final rule will provide numerous benefits for stakeholders, the Agency, industry, and the general public. The final revisions strengthen the empirical basis for and scope of reporting under subpart W so that reporting is based on empirical data accurately reflects total CH
                        <E T="52">4</E>
                         emissions and waste emissions from applicable facilities. These revisions include improvements to the calculation, monitoring, and reporting requirements, including updates to existing emission factors and emissions estimation methodologies, revisions to require reporting of additional data for new emission sources and address potential gaps in reporting, and revisions to collect data that will improve the EPA's understanding of the sector-specific processes or other factors that influence GHG emission rates, verification of collected data, or to complement or inform other EPA programs. The revisions will maintain and improve the quality of the data collected under part 98 where continued collection of information assists in evaluation and support of EPA programs and policies under provisions of the CAA.
                    </P>
                    <P>
                        Because this is a final reporting rule, the EPA did not quantify estimated emission reductions or monetize the benefits from such reductions that could be associated with this action. The benefits of the final amendments are based on their relevance to policy making, transparency, and market efficiency. The final amendments to the reporting system for petroleum and natural gas systems will benefit the EPA, other policymakers, and the public by increasing the completeness and accuracy of facility emissions data. Public data on emissions allows for accountability of emitters to the public. Improved facility-specific emissions data will aid local, state, and national policymakers as they evaluate and consider future climate change policy decisions and other policy decisions for criteria pollutants, ambient air quality standards, and toxic air emissions. The benefits of improved reporting of petroleum and natural gas systems GHG emissions to government also include enhancing existing programs, such as the Natural Gas STAR Program, that provide significant benefits, such as identifying cost-effective technologies and practices to reduce emissions of CH
                        <E T="52">4</E>
                         from operations in all of the major industry sectors—production, gathering and processing, transmission, and distribution. The Natural Gas STAR program leverages GHGRP reporting data to track partner petroleum and natural gas company activities related to their Methane Challenge commitments. The final changes to subpart W will increase knowledge of the location and magnitude of significant CH
                        <E T="52">4</E>
                         emissions sources in the petroleum and natural gas industry, and associated activities and technologies, which can result in improvements in technologies and the identification of new emissions reducing technologies.
                    </P>
                    <P>
                        Benefits to industry of improved GHG emissions monitoring and reporting under the proposed amendments include the value of having verifiable empirical data to present to the public to demonstrate appropriate 
                        <PRTPAGE P="42213"/>
                        environmental stewardship, and a better understanding of their emission levels and sources to identify opportunities to reduce emissions. The EPA also anticipates that improvements to monitoring and implementation of empirical measurement methods will result in emissions reductions. Based on activity data used to inform the U.S. GHG Inventory, the EPA estimated approximately 403.4 billion cubic feet of fugitive CH
                        <E T="52">4</E>
                         emissions (including fugitive leaks, venting, and flaring) in 2021, representing a potential loss of over $871 million 
                        <SU>88</SU>
                        <FTREF/>
                         to industry. To the extent that more frequent monitoring helps to identify and mitigate emissions from leakage, a robust reporting program based on empirical data can help industry demonstrate and disseminate their environmental achievements. Businesses and other innovators can use the data to determine and track their GHG footprints, find cost-saving efficiencies that reduce GHG emissions and save product, and foster technologies to protect public health and the environment and to reduce costs associated with fugitive emissions. Such monitoring also allows for inclusion of standardized GHG data into environmental management systems, providing the necessary information to track actual company performance and to demonstrate and disseminate their environmental achievements. Once facilities invest in the institutional knowledge and systems to monitor and report emissions, the cost of monitoring should fall and the accuracy of the accounting should continue to improve. The final amendments will continue to allow for facilities to benchmark themselves against similar facilities to understand better their relative standing within their industry and achieve and disseminate information about their environmental performance.
                    </P>
                    <FTNT>
                        <P>
                            <SU>88</SU>
                             Based on natural gas prices from EIA (current monthly average, April 2023). See 
                            <E T="03">https://www.eia.gov/dnav/ng/hist/rngwhhdm.htm.</E>
                        </P>
                    </FTNT>
                    <P>
                        In addition, transparent public data on emissions allows for accountability of polluters to the public who bear the cost of the pollution. The GHGRP serves as a powerful data resource and provides a critical tool for communities to identify nearby sources of GHGs and provide information to state and local governments. GHGRP data are easily accessible to the public via the EPA's online data publication tool, also known as FLIGHT (Facility Level Information on Greenhouse gases Tool) at: 
                        <E T="03">https://ghgdata.epa.gov/ghgp/main.do.</E>
                         FLIGHT is designed for the general public and allows users to view and sort GHG data from over 8,000 entities in a variety of ways including by location, industrial sector, and type of GHG emitted, and includes demographic data. Although the emissions reported to the EPA by reporting facilities are global pollutants, many of these facilities also release pollutants that have a more direct and local impact in the surrounding communities. Citizens, community groups, and labor unions have made use of public pollutant release data to negotiate directly with emitters to lower emissions, avoiding the need for additional regulatory action.
                    </P>
                    <P>The publicly available data generated by this final rule may be of particular interest to environmental justice communities. The EPA has previously engaged with representatives of communities with environmental justice concerns and heard directly from stakeholders regarding the health effects of air pollution associated with oil and gas facilities, the implications of climate change and associated extreme weather events for health and well-being in overburdened and vulnerable communities, and accessibility to data and information regarding sources near environmental justice communities. The data generated in this final reporting rule can be used to inform community residents or other stakeholders as they search for information about pollution that affects them, and may provide vital pollutant release data that is needed for advocates to push for stronger protections within their communities. This final rule substantially improves the data reported and made available to environmental justice communities by improving the accuracy, completeness, and relevance of the data to community members. Specifically, the disaggregation of reporting requirements within the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments to at least the well-pad and gathering boosting site-level, respectively, will provide communities with more localized information on GHG emissions from these segments that may impact their localities. Such information has previously been unavailable to affected environmental justice communities. Additionally, the final amendments will improve the quality and transparency of reported data to affected communities, for example, by providing data on other large release events, including the location, description, and volume of pollutants released. This final rule also requires reporting of data related to facilities that receive super-emitter event notifications, including the type of event resulting in the emissions and an indication of whether the emissions are included and reported under subpart W. This information provides transparency and accountability for large emissions releases and provides important data for impacted individuals, particularly in environmental justice communities.</P>
                    <P>Therefore, while the EPA has not quantified the benefits of these amendments to subpart W, the agency believes that they will be substantial, and further support a conclusion that the rule is reasonable and worthwhile. In addition, the focus on strengthening the empirical basis of the data that is the foundation of this final rule was mandated by Congress in the IRA.</P>
                    <HD SOURCE="HD1">VII. Statutory and Executive Order Reviews</HD>
                    <HD SOURCE="HD2">A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review</HD>
                    <P>
                        This action is a “significant regulatory action” as defined in Executive Order 12866, as amended by Executive Order 14094. Accordingly, the EPA submitted this action to the Office of Management and Budget (OMB) for Executive Order 12866 review. Documentation of any changes made in response to the Executive Order 12866 review is available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234. The EPA prepared an analysis of the potential impacts associated with this action. This analysis, 
                        <E T="03">Assessment of Burden Impacts for Greenhouse Gas Reporting Rule Revisions for Petroleum and Natural Gas Systems</E>
                        , is also available in the docket to this rulemaking and is briefly summarized in section VI. of this preamble.
                    </P>
                    <HD SOURCE="HD2">B. Paperwork Reduction Act (PRA)</HD>
                    <P>The information collection activities in this rule have been submitted for approval to the OMB under the PRA. The Information Collection Request (ICR) document that the EPA prepared has been assigned OMB Number 2060-0751 (EPA ICR number 2774.02). You can find a copy of the ICR in the docket for this rule and it is briefly summarized here. The information collection requirements are not enforceable until OMB approves them.</P>
                    <P>
                        The EPA estimates that the amendments will result in an increase in burden. The burden associated with the final rule is due to revisions that will expand reporting to include new emission sources or that expand the industry segments covered by existing emissions sources and that may impact 
                        <PRTPAGE P="42214"/>
                        the facilities that are required to report to subpart W; revisions to emissions calculation methodologies that will require additional monitoring; and revisions to collect additional data to more accurately reflect and verify total CH
                        <E T="52">4</E>
                         emissions in reports submitted to the GHGRP or to provide information for future implementation of the waste emissions charge under CAA section 136. As a result of these revisions, 567 new sources are expected to become subject to subpart W. Labor and O&amp;M costs are included for those new sources to comply with the reporting and recordkeeping costs detailed in EPA ICR number 2300.18, as well as costs to comply with these revisions.
                        <SU>89</SU>
                        <FTREF/>
                    </P>
                    <FTNT>
                        <P>
                            <SU>89</SU>
                             In addition to the costs to comply with these revisions, the 567 new sources will also incur the average subpart W reporter-level labor and O&amp;M costs, which differ by industry segment, from OMB Number 2060-0629 (EPA ICR number 2300.18) to comply with the subpart W requirements that were in place prior to these revisions.
                        </P>
                    </FTNT>
                    <P>
                        The estimated annual average burden is 1,902,792 hours and $183.6 million (per year) over the 3 years covered by this information collection. Further information on the EPA's assessment on the impact on burden can be found in the memorandum, 
                        <E T="03">Assessment of Burden Impacts for Greenhouse Gas Reporting Rule Revisions for Petroleum and Natural Gas Systems</E>
                        , in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
                    </P>
                    <P>
                        <E T="03">Respondents/affected entities:</E>
                         Owners and operators of petroleum and natural gas systems that must report their GHG emissions and other data to the EPA to comply with 40 CFR part 98.
                    </P>
                    <P>
                        <E T="03">Respondent's obligation to respond:</E>
                         The respondent's obligation to respond is mandatory under the authority provided in CAA sections 114 and 136.
                    </P>
                    <P>
                        <E T="03">Estimated number of respondents:</E>
                         3,077 (affected by final amendments).
                    </P>
                    <P>
                        <E T="03">Frequency of response:</E>
                         Annually.
                    </P>
                    <P>
                        <E T="03">Total estimated burden:</E>
                         1,902,792 hours (per year). Burden is defined at 5 CFR 1320.3(b).
                    </P>
                    <P>
                        <E T="03">Total estimated cost:</E>
                         $183.6 million, (per year), includes $14.1 million annualized operation &amp; maintenance costs.
                    </P>
                    <P>
                        An Agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves this ICR, the Agency will announce that approval in the 
                        <E T="04">Federal Register</E>
                         and publish a technical amendment to 40 CFR part 9 to display the OMB control number for the approved information collection activities contained in this final rule.
                    </P>
                    <HD SOURCE="HD2">C. Regulatory Flexibility Act (RFA)</HD>
                    <P>I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA. The small entities subject to the requirements of this action are small businesses in the petroleum and natural gas industry. Small entities include small businesses, small organizations, and small governmental jurisdictions. The EPA has determined that some small entities are affected because their production processes emit GHGs that must be reported.</P>
                    <P>
                        In the implementation of the GHGRP, the EPA previously determined thresholds that reduced the number of small businesses reporting. For example, petroleum and natural gas facilities generally only report to part 98 if all combined emissions from the facility, including stationary fuel combustion and other applicable manufacturing source categories, exceed 25,000 mtCO
                        <E T="52">2</E>
                        e per year. However, facilities from the Onshore Petroleum and Natural Gas Production, Natural Gas Distribution, Onshore Petroleum and Natural Gas Gathering and Boosting, and Onshore Natural Gas Transmission Pipeline industry segments must report if specific petroleum and natural gas emissions sources from these operations emit 25,000 mtCO
                        <E T="52">2</E>
                        e or more per year. These thresholds are intended to exclude smaller enterprises that, generally, are not significant emissions sources. The EPA estimates that in most cases, smaller enterprises have very small operations (such as a single family owning a few production wells) that are unlikely to cross the 25,000 mtCO
                        <E T="52">2</E>
                        e reporting threshold. The final revisions will not revise the threshold for existing subpart W reporters, therefore, we do not expect a significant number of small entities will be newly impacted under the final rule revisions.
                    </P>
                    <P>The amendments apply to 2,322 existing facilities and 567 new facilities that result from rule revisions that require the reporting of new emission sources or that expand the industry segments covered. The rule amendments predominantly apply to existing reporters and are amendments that will expand reporting to include new emission sources; add, remove, or refine emissions estimation methodologies to improve the accuracy and transparency of reported emission data; for the Onshore Natural Gas Production and Onshore Natural Gas Gathering and Boosting segments, revise reporting of emissions from a basin level to a site level; implement requirements to collect new or revised data; clarify or update provisions that have been misinterpreted; or streamline or simplify requirements by increasing flexibility for reporters or removing redundant requirements.</P>
                    <P>
                        The EPA conducted a small entity analysis that assessed the costs and impacts to small entities, including: (1) Revisions to add new emissions sources and expand the industry segments covered by existing emissions sources, (2) changes to improve existing monitoring or calculation methodologies, and (3) revisions to reporting and recordkeeping requirements for data provided to the program. The Agency anticipates that although a subset of small entity reporters (160-180) have a cost-to-revenue ratio (CRR) &gt; 1%, there are only a limited number (73-75) of small entities, primarily in the very small business size range (1-19 employees), that would be likely to have significant impacts with CRR &gt; 3%, reflecting a small proportion (6.3%-14.0%) of the total affected small entities. The mean CRR for these very small entities (1-19 employees) is estimated to be between 2.19% (2.11-2.28%) and 3.79% (3.47-4.11%) based on the incremental costs for existing reporting entities and between 2.78% (2.63-2.92%) and 4.79% (4.28-5.31%) based on the costs for newly reporting entities.
                        <SU>90</SU>
                        <FTREF/>
                         Details of this analysis are presented in the memorandum, 
                        <E T="03">Assessment of Burden Impacts for Greenhouse Gas Reporting Rule Revisions for Petroleum and Natural Gas Systems</E>
                        , available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234. Based on the results of this analysis, we have concluded that this action is not likely to have a significant regulatory burden for a substantial number of small entities and thus that this action will not have a significant economic impact on a substantial number of small entities.
                    </P>
                    <FTNT>
                        <P>
                            <SU>90</SU>
                             The EPA conducted a multi-level analysis to estimate mean CRRs for multiple scenarios. The mean CRR and associated 95-percent confidence intervals provide an estimate of the range of cost-to-sales rtios expected to apply to affected very small entities that would be expected in the total population.
                        </P>
                    </FTNT>
                    <HD SOURCE="HD2">D. Unfunded Mandates Reform Act (UMRA)</HD>
                    <P>
                        This action does not contain an unfunded mandate of $100 million or more (adjusted annually for inflation) as described in UMRA, 2 U.S.C. 1531-1538, for state, local, and tribal governments, in the aggregate, or the 
                        <PRTPAGE P="42215"/>
                        private sector in any one year, and does not significantly or uniquely affect small governments. The costs involved in this action are estimated not to exceed $100 million or more (adjusted for inflation, with the current threshold of approximately $198 million) in any one year. The yearly costs of this final action are presented in tables 7 and 8 of this preamble. The action in part implements mandate(s) specifically and explicitly set forth in CAA section 136.
                    </P>
                    <P>This final rule does not apply to governmental entities unless the government entity owns a facility in the petroleum and gas industry that directly emits GHG above part 98 applicability threshold levels. It does not impose any implementation responsibilities on state, local, or tribal governments and it is not expected to increase the cost of existing regulatory programs managed by those governments. Thus, the impact on governments affected by the final rule is expected to be minimal.</P>
                    <HD SOURCE="HD2">E. Executive Order 13132: Federalism</HD>
                    <P>
                        This action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government. This final rule does not apply to governmental entities unless the government entity owns a facility in the petroleum and gas industry (
                        <E T="03">e.g.</E>
                        , an LDC) that directly emits GHG above part 98 applicability threshold levels. Therefore, the EPA anticipates relatively few state or local government facilities will be affected.
                    </P>
                    <P>However, consistent with the EPA's policy to promote communications between the EPA and state and local governments, the EPA sought comments from small governments concerning the regulatory requirements that might significantly or uniquely affect them in the development of the final rule. Specifically, the EPA previously published an RFI seeking public comment in a non-regulatory docket to collect responses to a range of questions related to the Methane Emissions Reduction Program, including subpart W revisions (see Docket ID. No. EPA-HQ-OAR-2022-0875). The EPA received two comments from government entities supporting the use of empirical data and improvements to the accuracy of calculation methods under subpart W. The EPA also solicited comments on the 2023 Subpart W Proposal; the EPA did not receive any comments regarding concerns that this rule will significantly or uniquely affect small governments. All comments were considered during the development of the final rule.</P>
                    <HD SOURCE="HD2">F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments</HD>
                    <P>This action has tribal implications. However, it will neither impose substantial direct compliance costs on federally recognized Tribal governments, nor preempt tribal law. This regulation will apply directly to petroleum and natural gas facilities that may be owned by tribal governments that emit GHGs. However, it will generally only have tribal implications where the tribal entity owns a facility that directly emits GHGs above threshold levels; therefore, relatively few tribal facilities will be affected. Of the subpart W facilities currently reporting to the GHGRP in RY2021, we identified four facilities currently reporting to part 98 that are owned by one tribal parent company. In addition to tribes that will be directly impacted by the final revisions due to owning a facility subject to the requirements, the EPA anticipates that tribes could be impacted in cases where facilities subject to the final revisions are located on Tribal land. In particular, the EPA reviewed the location of the production wells reported by facilities under the Onshore Petroleum and Natural Gas Production segment and found production wells reported under subpart W on lands associated with approximately 20 tribes.</P>
                    <P>
                        Therefore, although the EPA anticipates that only one tribe will be directly subject to the rule, the EPA took a number of steps to provide information, consult with, and obtain input from tribal governments and representatives during the development of the rule. On November 4, 2022, the EPA published an RFI seeking public comment on a range of questions related to the Methane Emissions Reduction Program, including subpart W revisions (see Docket ID. No. EPA-HQ-OAR-2022-0875). The EPA received one comment from a tribal entity relevant to subpart W. The commenter supported the use of empirical data and improvements to the accuracy of calculation methods under subpart W, including the use of advanced CH
                        <E T="52">4</E>
                         detection technologies for leak surveys at well sites and compressor stations; these comments were considered during the development of the rule. The EPA further consulted with tribal officials under the EPA Policy on Consultation and Coordination with Indian Tribes early in the process of developing this regulation, to permit them to have meaningful and timely input into its development. On July 11, 2023, the EPA invited all 574 federally-recognized Tribes, Alaska Native Villages, and Alaska Native Corporations, to consult on the proposed revisions at a date and time developed in consultation with Tribes requesting consultation, with an anticipated consultation timeline of September 4, 2023; a copy of this letter is available in the docket to this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234. Only one Tribe participated in government-to-government consultation with the EPA. In response, the EPA met with the Ute Indian Tribe's Business Committee via video conference at 3:30 p.m. Eastern Time on September 20, 2023. The EPA provided several other opportunities for tribal input; the EPA opened the rule for public comment from August 1 to October 2, 2023, and hosted a virtual public hearing for the proposed revisions on August 21, 2023. The EPA provided a subsequent informational webinar on the technical aspects of the rule on September 7, 2023. The EPA has considered the tribal input from the coordination and consultation calls, informational webinar, and public comments in the development of the final rule.
                    </P>
                    <P>As required by section 7(a), the EPA's Tribal Consultation Official has certified that the requirements of the executive order have been met in a meaningful and timely manner. A copy of the certification is included in the docket for this action.</P>
                    <HD SOURCE="HD2">G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks</HD>
                    <P>The EPA interprets Executive Order 13045 as applying only to those regulatory actions that concern environmental health or safety risks that the EPA has reason to believe may disproportionately affect children, per the definition of “covered regulatory action” in section 2-202 of the Executive Order. This action regarding revisions to reporting requirements is not subject to Executive Order 13045 because it does not concern an environmental health risk or safety risk.</P>
                    <HD SOURCE="HD2">H. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use</HD>
                    <P>
                        This action is not a “significant energy action” because it is not likely to have a significant adverse effect on the supply, distribution or use of energy. The final amendments will expand reporting to include new emission sources; add, remove, or refine emissions estimation methodologies; improve the accuracy and transparency 
                        <PRTPAGE P="42216"/>
                        of reported emission data; for the Onshore Natural Gas Production and Onshore Natural Gas Gathering and Boosting segments, revise reporting of emissions from a basin level to a site level; implement requirements to collect new or revised data; clarify or update provisions that have been misinterpreted; or streamline or simplify requirements by increasing flexibility for reporters or removing redundant requirements. We are also finalizing revisions that streamline or simplify requirements or alleviate burden through revision, simplification, or removal of certain calculation, monitoring, recordkeeping, or reporting requirements. In general, these changes will not have a significant, adverse effect on the supply, distribution, or use of energy. In addition, the EPA is finalizing confidentiality determinations for new and revised data elements included in this rulemaking and for certain existing data elements for which a confidentiality determination has not previously been finalized. These amendments and confidentiality determinations do not make any changes to the existing monitoring, calculation, and reporting requirements under subpart W and are not likely to have a significant adverse effect on the supply, distribution, or use of energy.
                    </P>
                    <HD SOURCE="HD2">I. National Technology Transfer and Advancement Act and 1 CFR Part 51</HD>
                    <P>This action involves technical standards. The EPA has decided to incorporate by reference several standards in establishing monitoring requirements in these final amendments.</P>
                    <P>
                        For enclosed combustion devices, the EPA is finalizing a requirement to conduct a performance test to use the Tier 2 destruction efficiency and combustion efficiency. The test must be conducted in accordance with 40 CFR 60.5413b(b) or (d) or using EPA Other Test Method 52 (OTM-52), 
                        <E T="03">Method for Determination of Combustion Efficiency from Enclosed Combustors Located at Oil and Gas Production Facilities</E>
                        , dated September 26, 2023. In OTM-52, a gas sample is continuously extracted from the exhaust duct of an enclosed combustion device and conveyed to a gas analyzer(s) for determination of CO
                        <E T="52">2</E>
                        , CO, and hydrocarbon concentrations for the calculation of combustion efficiency. Anyone may access OTM-52 at 
                        <E T="03">https://www.epa.gov/emc/emc-other-test-methods</E>
                        . This standard is available to everyone at no cost; therefore, the method is reasonably available for reporters.
                    </P>
                    <P>
                        For facilities that conduct a performance test to calculate combustion slip, the EPA is finalizing a requirement that the performance test will be conducted in accordance with one of the test methods in 40 CFR 98.234(i), which include EPA Methods 18 and 320 as well as an alternate method, ASTM D6348-12 (Reapproved 2020), 
                        <E T="03">Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy</E>
                        , Approved December 1, 2020. The EPA is allowing the use of the alternate method ASTM D6348-12, which is based on the use of a Fourier transform infrared (FTIR) spectrometer for the identification and quantification of multicomponent gaseous compounds in stationary source effluent, in lieu of EPA Method 320. The EPA currently allows for the use of an earlier version of this method, ASTM D6348-03, under other subparts of part 98, including subparts I (Electronics Manufacturing), V (Nitric Acid Production), and OO (Fluorinated Gas Production), for the quantification of other GHGs. Therefore, the EPA is allowing ASTM D6348-12 to be used in subpart W to quantify CH
                        <E T="52">4</E>
                         emissions from combustion slip. Anyone may access the standard ASTM D6348-12 on the ASTM website (
                        <E T="03">https://www.astm.org/</E>
                        ) for additional information. The standard is available to everyone at a cost determined by the ASTM ($76). The ASTM also offers memberships or subscriptions that allow unlimited access to their methods. The cost of obtaining these methods is not a significant financial burden, making the methods reasonably available for reporters. The EPA will also make a copy of these documents available in hard copy at the appropriate EPA office (see the 
                        <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                         section of this preamble for more information) for review purposes only.
                    </P>
                    <HD SOURCE="HD2">J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations</HD>
                    <P>Because this is an information collection and reporting rule, it does not directly affect human health or environmental conditions and therefore the EPA cannot evaluate potentially disproportionate and adverse effects on communities with environmental justice concerns. Although this action does not directly affect human health or environmental conditions, we expect it will affect environmental justice concerns by greatly improving the availability, accuracy, and relevance of information about pollution in their communities.</P>
                    <P>
                        The EPA has developed improvements to the GHGRP in the final rule that benefit the public, including environmental justice communities, by increasing the completeness and accuracy of facility emissions data. The data that will be collected through this action will provide an important data resource for communities and the public to understand GHG emissions. Although the emissions reported to the EPA by reporting facilities are global pollutants, many of these facilities also release pollutants that have a more direct and local impact in the surrounding communities. Since facilities will be required to use prescribed calculation and monitoring methods, emissions data can be compared and analyzed, including locations of emissions sources. GHGRP data are easily accessible to the public via the EPA's online data publication tool (FLIGHT), available at: 
                        <E T="03">https://ghgdata.epa.gov/ghgp/main.do</E>
                        . FLIGHT allows users to view and sort GHG data for every reporting year starting with 2010 from over 8,000 entities in a variety of ways including by location, industrial sector, and type of GHG emitted, and provides supplementary demographic data that may be useful to communities with environmental justice concerns. This powerful data resource provides a critical tool for communities to identify nearby sources of GHGs, including methane and nitrous oxide, and to provide information to state and local governments. The EPA believes that the transparency provided by the data reported under these final revisions will ultimately encourage and result in reduction of GHG emissions and other co-pollutants, such as hazardous air pollutants and volatile organic compounds.
                    </P>
                    <P>
                        The final revisions to part 98 include requirements for reporting of GHG data from additional emission sources (other large release events, nitrogen removal units, produced water tanks, crankcase venting, and mud degassing), improvements to emissions calculation methodologies, and collection of data to support verification of GHG emissions and transparency. The disaggregation of reporting requirements within the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments to at least the well-pad and gathering boosting site-level, respectively, and the required reporting of geographical coordinates for other large release events, will provide communities with additional, more localized information on GHG emissions from these segments. Overall, these 
                        <PRTPAGE P="42217"/>
                        revisions will improve the quality, availability and relevance of the data collected under the program and available to communities, and generally will improve environmental justice outcomes.
                    </P>
                    <P>Finally, the EPA has promoted meaningful engagement from communities in developing the action, and in developing requirements that improve the quality of data submitted to the EPA, which are also available to communities as consistent with EPA's confidentiality determinations. The EPA has provided several opportunities for public engagement. The EPA opened the rule for public comment from August 1 to October 2, 2023, and hosted a virtual public hearing for the proposed revisions on August 21, 2023. The EPA provided a subsequent informational webinar on the technical aspects of the rule on September 7, 2023. The EPA has taken into consideration comments received from representatives and stakeholders in the development of this final rule.</P>
                    <HD SOURCE="HD2">K. Congressional Review Act (CRA)</HD>
                    <P>This action is subject to the CRA, and the EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. The Office of Information and Regulatory Affairs has determined that this action meets the criteria set forth by 5 U.S.C. 804(2).</P>
                    <HD SOURCE="HD2">L. Judicial Review</HD>
                    <P>
                        Under CAA section 307(b)(1), any petition for review of this final rule must be filed in the U.S. Court of Appeals for the District of Columbia Circuit by July 15, 2024. This final rule establishes requirements applicable to owners and operators of facilities in the petroleum and natural gas systems source category located across the United States that are subject to 40 CFR part 98 and therefore is “nationally applicable” within the meaning of CAA section 307(b)(1). Under CAA section 307(d)(7)(B), only an objection to this final rule that was raised with reasonable specificity during the period for public comment can be raised during judicial review. CAA section 307(d)(7)(B) also provides a mechanism for the EPA to convene a proceeding for reconsideration, “[i]f the person raising an objection can demonstrate to EPA that it was impracticable to raise such objection within [the period for public comment] or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule.” Any person seeking to make such a demonstration should submit a Petition for Reconsideration to the Office of the Administrator, Environmental Protection Agency, Room 3000, William Jefferson Clinton Building, 1200 Pennsylvania Ave. NW, Washington, DC 20460, with an electronic copy to the person listed in 
                        <E T="02">FOR FURTHER INFORMATION CONTACT</E>
                        , and the Associate General Counsel for the Air and Radiation Law Office, Office of General Counsel (Mail Code 2344A), Environmental Protection Agency, 1200 Pennsylvania Ave. NW, Washington, DC 20004. Note that under CAA section 307(b)(2), the requirements established by this final rule may not be challenged separately in any civil or criminal proceedings brought by the EPA to enforce these requirements.
                    </P>
                    <HD SOURCE="HD2">M. Determination Under CAA Section 307(d)</HD>
                    <P>Pursuant to CAA section 307(d)(1)(V), the Administrator determined that this rule is subject to the provisions of 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”).</P>
                    <HD SOURCE="HD2">N. Severability</HD>
                    <P>This final rule includes new and revised requirements for numerous provisions under various aspects of subpart W of the GHGRP. Therefore, this final rule is a multifaceted rule that addresses many separate things for independent reasons, as detailed in each respective portion of this preamble. We intend each portion of this rule to be severable from each other, though we took the approach of including all the parts in one rulemaking rather than promulgating multiple rules to ensure the changes are adopted and implemented in a coordinated manner, even though the changes are not inter-dependent.</P>
                    <P>For example, the EPA notes that our judgments regarding revisions for each industry segment consistent with our Clean Air Act authority and the directives in CAA section 136(h) reflect our determinations specific to considerations within each industry segment, while our judgment regarding the revisions to requirements for each type of source within each subpart W industry segment reflect our determinations specific to considerations for each source in each industry segment. The revisions for a given industry segment are intended to be and are implementable even absent revisions to the other industry segments (for example, Offshore Production revisions are independent from Onshore Petroleum and Natural Gas Production revisions), and likewise for each source within each industry segment, as they each independently ensure that the emissions reported under subpart W for the given source or industry segment at issue are consistent with the directives in CAA section 136(h) and improve the subpart W provisions as described in section II. of this preamble. Regarding revisions to requirements for each source being separate from each other, this includes, for a couple of examples, revisions to provisions for determining emissions emitted to the atmosphere being separate from revisions to provisions for determining emissions sent to a control device from a source as well as revisions to provisions for determining emissions emitted as an other large release event being separate from revisions to provisions for determining emissions from such a source when the emissions do not qualify as an other large release event. Accordingly, the EPA finds that revisions to each type of source in each industry segment are severable from revisions to each other type of source in each industry segment, and that at minimum revisions to each industry segment are severable from revisions to each of the other industry segments.</P>
                    <P>Additionally, our judgments regarding each calculation method for each source are likewise independent and do not rely on one another, as they each independently ensure that the emissions reported under subpart W for the given source or industry segment at issue are consistent with the directives in CAA section 136(h) and improve the subpart W provisions as described in section II. of this preamble. Accordingly, the EPA finds that each calculation method for each source is severable.</P>
                    <P>Finally, as described in section II. of this preamble, the EPA notes that there are changes the EPA is making related to amending certain requirements that apply to the general provisions, general stationary fuel combustion, and petroleum and natural gas systems source categories of the Greenhouse Gas Reporting Rule to improve calculation, monitoring, and reporting of greenhouse gas data for petroleum and natural gas systems facilities, as well as establishing and amending confidentiality determinations for the reporting of certain data elements to be added or substantially revised in these amendments. The EPA's overall GHGRP subpart W program continues to be fully implementable even in the absence of any one or more of these elements.</P>
                    <P>
                        Thus, the EPA has independently considered and adopted each of these portions of the final rule (including but 
                        <PRTPAGE P="42218"/>
                        not limited to the updates to each industry segment; each type of source in each industry segment; each calculation methodology for each source; requirements that apply to the general provisions, general stationary fuel combustion, and petroleum and natural gas systems source categories of the Greenhouse Gas Reporting Rule to improve calculation, monitoring, and reporting of greenhouse gas data for petroleum and natural gas systems facilities; and establishing and amending confidentiality determinations for the reporting of certain data elements to be added or substantially revised in these amendments) and each is severable should there be judicial review. If a court were to invalidate any one of these elements of the final rule, we intend the remainder of this action to remain effective. Importantly, we have designed these different elements of the program to function sensibly and independently, the supporting basis for each of these elements of the final rule reflects that they are independently justified and appropriate, and we find each portion appropriate even if one or more other parts of the rule has been set aside. For example, if a reviewing court were to invalidate any of the revisions to address potential gaps in reporting of emissions data for specific sectors, the other regulatory amendments, including not only the other revisions to address potential gaps but also the other changes to discrete elements of the subpart W provisions, remain fully operable. Moreover, this list is not intended to be exhaustive, and should not be viewed as an intention by the EPA to consider other parts of the rule not explicitly listed here as not severable from other parts of the rule.
                    </P>
                    <LSTSUB>
                        <HD SOURCE="HED">List of Subjects in 40 CFR Part 98</HD>
                        <P>Environmental protection, Greenhouse gases, Incorporation by reference, Reporting and recordkeeping requirements.</P>
                    </LSTSUB>
                    <SIG>
                        <NAME>Michael S. Regan,</NAME>
                        <TITLE>Administrator.</TITLE>
                    </SIG>
                    <P>For the reasons stated in the preamble, the Environmental Protection Agency amends title 40, chapter I, of the Code of Federal Regulations as follows:</P>
                    <PART>
                        <HD SOURCE="HED">PART 98—MANDATORY GREENHOUSE GAS REPORTING</HD>
                    </PART>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>1. The authority citation for part 98 continues to read as follows:</AMDPAR>
                        <AUTH>
                            <HD SOURCE="HED">Authority:</HD>
                            <P> 42 U.S.C. 7401-7671q.</P>
                        </AUTH>
                    </REGTEXT>
                    <SUBPART>
                        <HD SOURCE="HED">Subpart A—General Provision</HD>
                    </SUBPART>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>2. Amend § 98.1 by revising paragraph (c) to read as follows:</AMDPAR>
                        <SECTION>
                            <SECTNO>§ 98.1</SECTNO>
                            <SUBJECT>Purpose and scope.</SUBJECT>
                            <STARS/>
                            <P>
                                (c) For facilities required to report under onshore petroleum and natural gas production under subpart W of this part, the terms 
                                <E T="03">Owner</E>
                                 and 
                                <E T="03">Operator</E>
                                 used in this subpart have the same definition as 
                                <E T="03">Onshore petroleum and natural gas production owner or operator,</E>
                                 as defined in § 98.238. For facilities required to report under onshore petroleum and natural gas gathering and boosting under subpart W of this part, the terms 
                                <E T="03">Owner</E>
                                 and 
                                <E T="03">Operator</E>
                                 used in this subpart have the same definition as 
                                <E T="03">Gathering and boosting system owner or operator,</E>
                                 as defined in § 98.238. For facilities required to report under onshore natural gas transmission pipeline under subpart W of this part, the terms 
                                <E T="03">Owner</E>
                                 and 
                                <E T="03">Operator</E>
                                 used in this subpart have the same definition as 
                                <E T="03">Onshore natural gas transmission pipeline owner or operator,</E>
                                 as defined in § 98.238.
                            </P>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>3. Amend § 98.2 by revising paragraph (i)(3) and adding paragraph (i)(7) to read as follows:</AMDPAR>
                        <SECTION>
                            <SECTNO>§ 98.2</SECTNO>
                            <SUBJECT>Who must report?</SUBJECT>
                            <STARS/>
                            <P>(i) * * *</P>
                            <P>(3) If the operations of a facility or supplier are changed such that all applicable processes and operations subject to paragraphs (a)(1) through (4) of this section cease to operate, then the owner or operator may discontinue complying with this part for the reporting years following the year in which cessation of such operations occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting and certifies to the closure of all applicable processes and operations no later than March 31 of the year following such changes. If one or more processes or operations subject to paragraphs (a)(1) through (4) of this section at a facility or supplier cease to operate, but not all applicable processes or operations cease to operate, then the owner or operator is exempt from reporting for any such processes or operations in the reporting years following the reporting year in which cessation of the process or operation occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting for the process or operation no later than March 31 following the first reporting year in which the process or operation has ceased for an entire reporting year. Cessation of operations in the context of underground coal mines includes, but is not limited to, abandoning and sealing the facility. This paragraph (i)(3) does not apply to seasonal or other temporary cessation of operations. This paragraph (i)(3) does not apply to the municipal solid waste landfills source category (subpart HH of this part), or the industrial waste landfills source category (subpart TT of this part). This paragraph (i)(3) does not apply when there is a change in the owner or operator for facilities in industry segments with a unique definition of facility as defined in § 98.238 of the petroleum and natural gas systems source category (subpart W of this part), unless the changes result in permanent cessation of all applicable processes and operations. The owner or operator must resume reporting for any future calendar year during which any of the GHG-emitting processes or operations resume operation.</P>
                            <STARS/>
                            <P>(7) If a facility in an industry segment with a unique definition of facility as defined in § 98.238 of the petroleum and natural gas systems source category (subpart W of this part) undergoes the type of change in owner or operator specified in paragraph § 98.4(n)(4) of this subpart, then the prior owner or operator may discontinue complying with the reporting requirements of this part for the facility for the reporting years following the year in which the change in owner or operator occurred, provided that the prior owner or operator submits a notification to the Administrator that announces the discontinuation of reporting no later than March 31 of the year following such change.</P>
                            <STARS/>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>4. Amend § 98.4 by revising the first sentence of paragraph (h) and adding paragraph (n) to read as follows:</AMDPAR>
                        <SECTION>
                            <SECTNO>§ 98.4</SECTNO>
                            <SUBJECT>Authorization and responsibilities of the designated representative.</SUBJECT>
                            <STARS/>
                            <P>
                                (h) 
                                <E T="03">Changes in owners and operators.</E>
                                 Except as provided in paragraph (n) of this section, in the event an owner or operator of the facility or supplier is not included in the list of owners and operators in the certificate of representation under this section for the facility or supplier, such owner or operator shall be deemed to be subject to and bound by the certificate of representation, the representations, actions, inactions, and submissions of the designated representative and any 
                                <PRTPAGE P="42219"/>
                                alternate designated representative of the facility or supplier, as if the owner or operator were included in such list. * * *
                            </P>
                            <STARS/>
                            <P>
                                (n) 
                                <E T="03">Alternative provisions for changes in owners and operators for industry segments with a unique definition of facility as defined in § 98.238.</E>
                                 When there is a change to the owner or operator of a facility required to report under the onshore petroleum and natural gas production, natural gas distribution, onshore petroleum and natural gas gathering and boosting, or onshore natural gas transmission pipeline industry segments of subpart W of this part, or a change to the owner or operator for some emission sources from the facility in one of these industry segments, the provisions specified in paragraphs (n)(1) through (4) of this section apply for the respective type of change in owner or operator.
                            </P>
                            <P>(1) If the entire facility is acquired by an owner or operator that does not already have a reporting facility in the same industry segment and basin (for onshore petroleum and natural gas production or onshore petroleum and natural gas gathering and boosting) or state (for natural gas distribution), then within 90 days after the change in the owner or operator, the designated representative or any alternate designated representative shall submit a certificate of representation that is complete under this section. If the new owner or operator already had emission sources specified in § 98.232(c), (i), (j), or (m), as applicable, prior to the acquisition in the same basin (for onshore petroleum and natural gas production or onshore petroleum and natural gas gathering and boosting) or state (for natural gas distribution) as the acquired facility but had not previously met the applicability requirements in §§ 98.2(a) and 98.231, then per the applicable definition of facility in § 98.238, the previously owned applicable emission sources must be included in the acquired facility. The new owner or operator and the new designated representative shall be responsible for submitting the annual report for the facility for the entire reporting year beginning with the reporting year in which the acquisition occurred.</P>
                            <P>(2) If the entire facility is acquired by an owner or operator that already has a reporting facility in the same industry segment and basin (for onshore petroleum and natural gas production or onshore petroleum and natural gas gathering and boosting) or state (for natural gas distribution), the new owner or operator shall merge the acquired facility with their existing facility for purposes of the annual GHG report. The owner or operator shall also follow the provisions of § 98.2(i)(6) to notify EPA that the acquired facility will discontinue reporting and shall provide the e-GGRT identification number of the merged, or reconstituted, facility. The owner or operator of the merged facility shall be responsible for submitting the annual report for the merged facility for the entire reporting year beginning with the reporting year in which the acquisition occurred.</P>
                            <P>
                                (3) If only some emission sources from the facility are acquired by one or more new owners or operators, the existing owner or operator (
                                <E T="03">i.e.,</E>
                                 the owner or operator of the portion of the facility that is not sold) shall continue to report under subpart W of this part for the retained emission sources unless and until that facility meets one of the criteria in § 98.2(i). Each owner or operator that acquires emission sources from the facility must account for those acquired emission sources according to paragraph (n)(3)(i) or (ii) of this section, as applicable.
                            </P>
                            <P>(i) If the purchasing owner or operator that acquires only some of the emission sources from the existing facility does not already have a reporting facility in the same industry segment and basin (for onshore petroleum and natural gas production or onshore petroleum and natural gas gathering and boosting) or state (for natural gas distribution), the purchasing owner or operator shall begin reporting as a new facility. The new facility must include the acquired emission sources specified in § 98.232(c), (i), (j), or (m), as applicable, and any emission sources the purchasing owner or operator already owned in the same industry segment and basin (for onshore petroleum and natural gas production or onshore petroleum and natural gas gathering and boosting) or state (for natural gas distribution). The designated representative for the new facility must be selected by the purchasing owner or operator according to the schedule and procedure specified in paragraphs (b) through (d) of this section. The purchasing owner or operator shall be responsible for submitting the annual report for the new facility for the entire reporting year beginning with the reporting year in which the acquisition occurred. The purchasing owner or operator shall continue to report under subpart W of this part for the new facility unless and until that facility meets one of the criteria in § 98.2(i).</P>
                            <P>(ii) If the purchasing owner or operator that acquires only some of the emission sources from the existing facility already has a reporting facility in the same industry segment and basin (for onshore petroleum and natural gas production or onshore petroleum and natural gas gathering and boosting) or state (for natural gas distribution), then per the applicable definition of facility in § 98.238, the purchasing owner or operator must add the acquired emission sources specified in § 98.232(c), (i), (j), or (m), as applicable, to their existing facility for purposes of reporting under subpart W of this part. The purchasing owner or operator shall be responsible for submitting the annual report for the entire facility, including the acquired emission sources, for the entire reporting year beginning with the reporting year in which the acquisition occurred.</P>
                            <P>(4) If all the emission sources from a reporting facility are sold to multiple owners or operators within the same reporting year, such that the prior owner or operator of the facility does not retain any of the emission sources, then the prior owner or operator of the facility shall notify EPA within 90 days of the last transaction that all of the facility's emission sources were acquired by multiple purchasers, including the identity of the purchasers. Each owner or operator that acquires emission sources from a facility shall account for those sources according to paragraph (n)(3)(i) or (ii) of this section, as applicable.</P>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>5. Amend § 98.6 by revising the definitions “Dehydrator,” “Dehydrator vent emissions,” “Desiccant,” and “Vapor recovery system” to read as follows:</AMDPAR>
                        <SECTION>
                            <SECTNO>§ 98.6</SECTNO>
                            <SUBJECT>Definitions.</SUBJECT>
                            <STARS/>
                            <P>
                                <E T="03">Dehydrator</E>
                                 means a device in which a liquid absorbent (including ethylene glycol, diethylene glycol, or triethylene glycol) or desiccant directly contacts a natural gas stream to remove water vapor.
                            </P>
                            <P>
                                <E T="03">Dehydrator vent emissions</E>
                                 means natural gas and CO
                                <E T="52">2</E>
                                 released from a natural gas dehydrator system absorbent (typically glycol) regenerator still vent and, if present, a flash tank separator, to the atmosphere, flare, regenerator fire-box/fire tubes, or vapor recovery system. Emissions include stripping natural gas and motive natural gas used in absorbent circulation pumps.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Desiccant</E>
                                 means a material used in solid-bed dehydrators to remove water from raw natural gas by adsorption or absorption. Desiccants include, but are not limited to, molecular sieves, 
                                <PRTPAGE P="42220"/>
                                activated alumina, pelletized calcium chloride, lithium chloride and granular silica gel material. Wet natural gas is passed through a bed of the granular or pelletized solid adsorbent or absorbent in these dehydrators. As the wet gas contacts the surface of the particles of desiccant material, water is adsorbed on the surface or absorbed and dissolves the surface of these desiccant particles. Passing through the entire desiccant bed, almost all of the water is adsorbed onto or absorbed into the desiccant material, leaving the dry gas to exit the contactor.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Vapor recovery system</E>
                                 means any equipment located at the source of potential gas emissions to the atmosphere or to a flare, that is composed of piping, connections, and, if necessary, flow-inducing devices, and that is used for routing the gas back into the process as a product and/or fuel. For purposes of § 98.233, routing emissions from a dehydrator regenerator still vent or flash tank separator vent to a regenerator fire-box/fire tubes does not meet the definition of vapor recovery system.
                            </P>
                            <STARS/>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>6. Amend § 98.7 by redesignating paragraphs (d)(36) through (50) as (d)(37) though (51), respectively, adding new paragraph (d)(36), and adding paragraph (m)(15) to read as follows:</AMDPAR>
                        <SECTION>
                            <SECTNO>§ 98.7</SECTNO>
                            <SUBJECT>What standardized methods are incorporated by reference into this part?</SUBJECT>
                            <STARS/>
                            <P>(d) * * *</P>
                            <P>(36) ASTM D6348-12 (Reapproved 2020) Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, Approved December 1, 2020, IBR approved for § 98.234(i).</P>
                            <STARS/>
                            <P>(m) * * *</P>
                            <P>
                                (15) Other Test Method 52 (OTM-52), Method for Determination of Combustion Efficiency from Enclosed Combustors Located at Oil and Gas Production Facilities, dated September 26, 2023, 
                                <E T="03">https://www.epa.gov/emc/emc-other-test-methods</E>
                                , IBR approved for § 98.233(n).
                            </P>
                            <STARS/>
                        </SECTION>
                    </REGTEXT>
                    <SUBPART>
                        <HD SOURCE="HED">Subpart C—General Stationary Fuel Combustion Sources</HD>
                    </SUBPART>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>7. Amend § 98.33 by revising parameter “EF” of equation C-8 in paragraph (c)(1) introductory text, parameter “EF” of equation C-8a in paragraph (c)(1)(i), parameter “EF” of equation C-8b in paragraph (c)(1)(ii), parameter “EF” of equation C-9a in paragraph (c)(2), and parameter “EF” of equation C-10 in paragraph (c)(4) introductory text to read as follows:</AMDPAR>
                        <SECTION>
                            <SECTNO>§ 98.33</SECTNO>
                            <SUBJECT>Calculating GHG emissions.</SUBJECT>
                            <STARS/>
                            <P>(c) * * *</P>
                            <P>(1) * * *</P>
                            <FP SOURCE="FP-2">Where: * * *</FP>
                            <EXTRACT>
                                <FP SOURCE="FP-2">
                                    EF = Fuel-specific default emission factor for CH
                                    <E T="52">4</E>
                                     or N
                                    <E T="52">2</E>
                                    O, from table C-2 to this subpart (kg CH
                                    <E T="52">4</E>
                                     or N
                                    <E T="52">2</E>
                                    O per mmBtu), except for natural gas-fired reciprocating internal combustion engines and gas turbines at facilities subject to subpart W of this part, which must use a CH
                                    <E T="52">4</E>
                                     emission factor determined in accordance with § 98.233(z)(4).
                                </FP>
                                <STARS/>
                            </EXTRACT>
                            <P>(i) * * *</P>
                            <FP SOURCE="FP-2">Where: * * *</FP>
                            <EXTRACT>
                                <FP SOURCE="FP-2">
                                    EF = Fuel-specific default emission factor for CH
                                    <E T="52">4</E>
                                     or N
                                    <E T="52">2</E>
                                    O, from table C-2 to this subpart (kg CH
                                    <E T="52">4</E>
                                     or N
                                    <E T="52">2</E>
                                    O per mmBtu), except for natural gas-fired reciprocating internal combustion engines and gas turbines at facilities subject to subpart W of this part, which must use a CH
                                    <E T="52">4</E>
                                     emission factor determined in accordance with § 98.233(z)(4).
                                </FP>
                                <STARS/>
                            </EXTRACT>
                            <P>(ii) * * *</P>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where: * * *</FP>
                                <FP SOURCE="FP-2">
                                    EF = Fuel-specific default emission factor for CH
                                    <E T="52">4</E>
                                     or N
                                    <E T="52">2</E>
                                    O, from table C-2 to this subpart (kg CH
                                    <E T="52">4</E>
                                     or N
                                    <E T="52">2</E>
                                    O per mmBtu), except for natural gas-fired reciprocating internal combustion engines and gas turbines at facilities subject to subpart W of this part, which must use a CH
                                    <E T="52">4</E>
                                     emission factor determined in accordance with § 98.233(z)(4).
                                </FP>
                                <STARS/>
                            </EXTRACT>
                            <P>(2) * * *</P>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where: * * *</FP>
                                <FP SOURCE="FP-2">
                                    EF = Fuel-specific default emission factor for CH
                                    <E T="52">4</E>
                                     or N
                                    <E T="52">2</E>
                                    O, from table C-2 to this subpart (kg CH
                                    <E T="52">4</E>
                                     or N
                                    <E T="52">2</E>
                                    O per mmBtu), except for natural gas-fired reciprocating internal combustion engines and gas turbines at facilities subject to subpart W of this part, which must use a CH
                                    <E T="52">4</E>
                                     emission factor determined in accordance with § 98.233(z)(4).
                                </FP>
                                <STARS/>
                            </EXTRACT>
                            <P>(4) * * *</P>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where: * * *</FP>
                                <FP SOURCE="FP-2">
                                    EF = Fuel-specific default emission factor for CH
                                    <E T="52">4</E>
                                     or N
                                    <E T="52">2</E>
                                    O, from table C-2 to this subpart (kg CH
                                    <E T="52">4</E>
                                     or N
                                    <E T="52">2</E>
                                    O per mmBtu), except for natural gas-fired reciprocating internal combustion engines and gas turbines at facilities subject to subpart W of this part, which must use a CH
                                    <E T="52">4</E>
                                     emission factor determined in accordance with § 98.233(z)(4).
                                </FP>
                            </EXTRACT>
                            <STARS/>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>8. Amend § 98.36 by adding paragraphs (b)(12), (c)(1)(xii), and (c)(3)(xi) to read as follows:</AMDPAR>
                        <SECTION>
                            <SECTNO>§ 98.36</SECTNO>
                            <SUBJECT>Data reporting requirements.</SUBJECT>
                            <STARS/>
                            <P>(b) * * *</P>
                            <P>
                                (12) For natural gas-fired reciprocating internal combustion engines or gas turbines at facilities subject to subpart W of this part, which must use a CH
                                <E T="52">4</E>
                                 emission factor determined in accordance with § 98.233(z)(4), you must also report:
                            </P>
                            <P>
                                (i) Type of equipment (
                                <E T="03">i.e.</E>
                                , two-stroke lean-burn reciprocating internal combustion engine, four-stroke lean-burn reciprocating internal combustion engine, four-stroke rich-burn reciprocating internal combustion engine, or gas turbine).
                            </P>
                            <P>
                                (ii) Method by which the CH
                                <E T="52">4</E>
                                 emission factor was determined: performance test, manufacturer data, or default emission factor.
                            </P>
                            <P>
                                (iii) Value of the CH
                                <E T="52">4</E>
                                 emission factor.
                            </P>
                            <P>(c) * * *</P>
                            <P>(1) * * *</P>
                            <P>
                                (xii) For natural gas-fired reciprocating internal combustion engines or gas turbines at facilities subject to subpart W of this part, which must use a CH
                                <E T="52">4</E>
                                 emission factor determined in accordance with § 98.233(z)(4), you must report the equipment type (
                                <E T="03">i.e.</E>
                                , two-stroke lean-burn reciprocating internal combustion engine, four-stroke lean-burn reciprocating internal combustion engine, four-stroke rich-burn reciprocating internal combustion engine, and gas turbine), the method by which the CH
                                <E T="52">4</E>
                                 emission factor was determined (
                                <E T="03">i.e.</E>
                                , performance test, manufacturer data, or default emission factor), and the average value of the CH
                                <E T="52">4</E>
                                 emission factor.
                            </P>
                            <STARS/>
                            <P>(3) * * *</P>
                            <P>
                                (xi) For natural gas-fired reciprocating internal combustion engines or gas turbines at facilities subject to subpart W of this part, which must use a CH
                                <E T="52">4</E>
                                 emission factor determined in accordance with § 98.233(z)(4), you must report the equipment type (
                                <E T="03">i.e.</E>
                                , two-stroke lean-burn reciprocating internal combustion engine, four-stroke lean-burn reciprocating internal combustion engine, four-stroke rich-burn reciprocating internal combustion engine, and gas turbine) the method by which the CH
                                <E T="52">4</E>
                                 emission factor was determined (
                                <E T="03">i.e.</E>
                                , performance test, manufacturer data, or default emission factor), and the average value of the CH
                                <E T="52">4</E>
                                 emission factor.
                            </P>
                            <STARS/>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>
                            9. Amend table C-2 to subpart C of part 98 by revising the entry “Natural Gas” to read as follows:
                            <PRTPAGE P="42221"/>
                        </AMDPAR>
                        <GPOTABLE COLS="3" OPTS="L1,i1" CDEF="s100,16C,16C">
                            <TTITLE>
                                Table C-2 to Subpart C of Part 98—Default CH
                                <E T="0732">4</E>
                                 and N
                                <E T="0732">2</E>
                                O Emission Factors for Various Types of Fuel
                            </TTITLE>
                            <BOXHD>
                                <CHED H="1">Fuel type</CHED>
                                <CHED H="1">
                                    Default CH
                                    <E T="0732">4</E>
                                    <LI>emission factor</LI>
                                    <LI>
                                        (kg CH
                                        <E T="0732">4</E>
                                        /mmBtu)
                                    </LI>
                                </CHED>
                                <CHED H="1">
                                    Default N
                                    <E T="0732">2</E>
                                    O
                                    <LI>emission factor</LI>
                                    <LI>
                                        (kg N
                                        <E T="0732">2</E>
                                        O/mmBtu)
                                    </LI>
                                </CHED>
                            </BOXHD>
                            <ROW>
                                <ENT I="22"> </ENT>
                            </ROW>
                            <ROW>
                                <ENT I="28">*     *     *     *     *     *     *</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">
                                    Natural Gas
                                    <SU>1</SU>
                                </ENT>
                                <ENT>
                                    1.0 × 10−
                                    <SU>03</SU>
                                </ENT>
                                <ENT>
                                    1.0 × 10−
                                    <SU>04</SU>
                                </ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                            </ROW>
                            <ROW>
                                <ENT I="28">*     *     *     *     *     *     *</ENT>
                            </ROW>
                            <ROW>
                                <ENT>  * * * * *</ENT>
                            </ROW>
                            <TNOTE>
                                <SU>1</SU>
                                 Reporters subject to subpart W of this part may only use the default CH
                                <E T="0732">4</E>
                                 emission factor for natural gas-fired combustion units that are not reciprocating internal combustion engines or gas turbines. For natural gas-fired reciprocating internal combustion engines or gas turbines, at facilities subject to subpart W of this part, reporters must use a CH
                                <E T="52">4</E>
                                 emission factor determined in accordance with § 98.233(z)(4).
                            </TNOTE>
                        </GPOTABLE>
                        <STARS/>
                    </REGTEXT>
                    <SUBPART>
                        <HD SOURCE="HED">Subpart W—Petroleum and Natural Gas Systems</HD>
                    </SUBPART>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>10. Amend § 98.230 by revising paragraphs (a)(2), (3), and (9) to read as follows:</AMDPAR>
                        <SECTION>
                            <SECTNO>§ 98.230</SECTNO>
                            <SUBJECT>Definition of the source category.</SUBJECT>
                            <P>(a) * * *</P>
                            <P>
                                (2) 
                                <E T="03">Onshore petroleum and natural gas production.</E>
                                 Onshore petroleum and natural gas production means all equipment on a single well-pad or associated with a single well-pad (including but not limited to compressors, generators, dehydrators, storage vessels, engines, boilers, heaters, flares, separation and processing equipment, and portable non-self-propelled equipment, which includes well drilling and completion equipment, workover equipment, and leased, rented or contracted equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating of petroleum and/or natural gas (including condensate). This equipment also includes associated storage or measurement vessels, all petroleum and natural gas production equipment located on islands, artificial islands, or structures connected by a causeway to land, an island, or an artificial island. Onshore petroleum and natural gas production also means all equipment on or associated with a single enhanced oil recovery (EOR) well-pad using CO2 or natural gas injection.
                            </P>
                            <P>
                                (3) 
                                <E T="03">Onshore natural gas processing.</E>
                                 Onshore natural gas processing means the forced extraction of natural gas liquids (NGLs) from field gas, fractionation of mixed NGLs to natural gas products, or both. Natural gas processing does not include a Joule-Thomson valve, a dew point depression valve, or an isolated or standalone Joule-Thomson skid. This segment also includes all residue gas compression equipment owned or operated by the natural gas processing plant.
                            </P>
                            <STARS/>
                            <P>
                                (9) 
                                <E T="03">Onshore petroleum and natural gas gathering and boosting.</E>
                                 Onshore petroleum and natural gas gathering and boosting means gathering pipelines and other equipment used to collect petroleum and/or natural gas from onshore production gas or oil wells and used to compress, dehydrate, sweeten, or transport the petroleum and/or natural gas to a downstream endpoint, typically a natural gas processing facility, a natural gas transmission pipeline or a natural gas distribution pipeline. Gathering and boosting equipment includes, but is not limited to gathering pipelines, separators, compressors, acid gas removal units, dehydrators, pneumatic devices/pumps, storage vessels, engines, boilers, heaters, and flares. Gathering and boosting equipment does not include equipment reported under any other industry segment defined in this section. Gathering pipelines operating on a vacuum and gathering pipelines with a GOR less than 300 standard cubic feet per stock tank barrel (scf/STB) are not included in this industry segment (oil here refers to hydrocarbon liquids of all API gravities).
                            </P>
                            <STARS/>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>11. Amend § 98.232 by:</AMDPAR>
                        <AMDPAR>a. Revising paragraphs (a) and (b);</AMDPAR>
                        <AMDPAR>b. Adding paragraph (c)(2);</AMDPAR>
                        <AMDPAR>c. Revising paragraphs (c)(10), (17), and (21);</AMDPAR>
                        <AMDPAR>d. Adding paragraphs (c)(23) through (25);</AMDPAR>
                        <AMDPAR>e. Revising paragraphs (d)(5) and (7);</AMDPAR>
                        <AMDPAR>f. Adding paragraphs (d)(8) through (11);</AMDPAR>
                        <AMDPAR>g. Revising paragraphs (e)(3) and (8);</AMDPAR>
                        <AMDPAR>h. Adding paragraphs (e)(9) through (11);</AMDPAR>
                        <AMDPAR>i. Revising paragraphs (f)(6) and (8);</AMDPAR>
                        <AMDPAR>j. Adding paragraphs (f)(9) through (13);</AMDPAR>
                        <AMDPAR>k. Revising paragraphs (g)(6) and (7);</AMDPAR>
                        <AMDPAR>l. Adding paragraphs (g)(8) through (11);</AMDPAR>
                        <AMDPAR>m. Revising paragraphs (h)(7) and (8);</AMDPAR>
                        <AMDPAR>n. Adding paragraphs (h)(9) through (11) and (i)(8) through (11);</AMDPAR>
                        <AMDPAR>o. Revising paragraphs (j)(3), (6), and (10);</AMDPAR>
                        <AMDPAR>p. Adding paragraphs (j)(13) and (14); and</AMDPAR>
                        <AMDPAR>q. Revising paragraph (m).</AMDPAR>
                        <P>The revisions and additions read as follows:</P>
                        <SECTION>
                            <SECTNO>§ 98.232</SECTNO>
                            <SUBJECT>GHGs to report.</SUBJECT>
                            <P>
                                (a) You must report CO
                                <E T="52">2</E>
                                , CH
                                <E T="52">4</E>
                                , and N
                                <E T="52">2</E>
                                O emissions from each industry segment specified in paragraphs (b) through (j) and (m) of this section, CO2, CH
                                <E T="52">4</E>
                                , and N
                                <E T="52">2</E>
                                O emissions from each flare as specified in paragraphs (b) through (j) of this section, and stationary and portable combustion emissions as applicable as specified in paragraph (k) of this section. You must also report the information specified in paragraph (l) of this section, as applicable.
                            </P>
                            <P>
                                (b) For offshore petroleum and natural gas production, report CO
                                <E T="52">2</E>
                                , CH
                                <E T="52">4</E>
                                , and N
                                <E T="52">2</E>
                                O emissions from the following sources. Offshore platforms do not need to report emissions from portable equipment.
                            </P>
                            <P>
                                (1) Equipment leaks (
                                <E T="03">i.e.</E>
                                , fugitives), vented emission, and flare emission source types as identified by Bureau of Ocean Energy Management (BOEM) in compliance with 30 CFR 550.302 through 304.
                            </P>
                            <P>(2) Other large release events.</P>
                            <P>(c) * * *</P>
                            <P>(2) Blowdown vent stacks.</P>
                            <STARS/>
                            <P>(10) Hydrocarbon liquids and produced water storage tank emissions.</P>
                            <STARS/>
                            <P>(17) Acid gas removal unit vents and nitrogen removal unit vents.</P>
                            <STARS/>
                            <P>(21) Equipment leaks listed in paragraph (c)(21)(i) or (ii) of this section, as applicable:</P>
                            <P>
                                (i) Equipment leaks from components including valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other components (such as instruments, loading arms, 
                                <PRTPAGE P="42222"/>
                                stuffing boxes, compressor seals, dump lever arms, and breather caps, but does not include components listed in paragraph (c)(11) or (19) of this section, and it does not include thief hatches or other openings on a storage vessel).
                            </P>
                            <P>(ii) Equipment leaks from major equipment including wellheads, separators, meters/piping, compressors, dehydrators, heaters, and storage vessels.</P>
                            <STARS/>
                            <P>(23) Other large release events.</P>
                            <P>(24) Drilling mud degassing.</P>
                            <P>(25) Crankcase vents.</P>
                            <P>(d) * * *</P>
                            <P>(5) Acid gas removal unit vents and nitrogen removal unit vents.</P>
                            <STARS/>
                            <P>(7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters, and equipment leaks from all other components in gas service (not including thief hatches or other openings on storage vessels) that either are subject to equipment leak standards for onshore natural gas processing plants in § 60.5400b or § 60.5401b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).</P>
                            <P>(8) Natural gas pneumatic device venting.</P>
                            <P>(9) Other large release events.</P>
                            <P>(10) Hydrocarbon liquids and produced water storage tank emissions.</P>
                            <P>(11) Crankcase vents.</P>
                            <P>(e) * * *</P>
                            <P>(3) Condensate storage tanks.</P>
                            <STARS/>
                            <P>(8) Equipment leaks from all other components that are not listed in paragraph (e)(1), (2), or (7) of this section and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, or that you elect to survey using a leak detection method described in § 98.234(a). The other components subject to this paragraph (e)(8) also do not include thief hatches or other openings on a storage vessel.</P>
                            <P>(9) Other large release events.</P>
                            <P>(10) Dehydrator vents.</P>
                            <P>(11) Crankcase vents.</P>
                            <P>(f) * * *</P>
                            <P>(6) Equipment leaks from all other components that are associated with storage stations, are not listed in paragraph (f)(1), (2), or (5) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a). The other components subject to this paragraph (f)(6) do not include thief hatches or other openings on a storage vessel.</P>
                            <STARS/>
                            <P>(8) Equipment leaks from all other components that are associated with storage wellheads, are not listed in paragraph (f)(1), (2), or (7) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).</P>
                            <P>(9) Other large release events.</P>
                            <P>(10) Dehydrator vents.</P>
                            <P>(11) Blowdown vent stacks.</P>
                            <P>(12) Condensate storage tanks.</P>
                            <P>(13) Crankcase vents.</P>
                            <P>(g) * * *</P>
                            <P>(6) Equipment leaks from all components in gas service that are associated with a vapor recovery compressor, are not listed in paragraph (g)(1) or (2) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).</P>
                            <P>(7) Equipment leaks from all components in gas service that are not associated with a vapor recovery compressor, are not listed in paragraph (g)(1) or (2) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).</P>
                            <P>(8) Other large release events.</P>
                            <P>(9) Blowdown vent stacks.</P>
                            <P>(10) Acid gas removal unit vents and nitrogen removal unit vents.</P>
                            <P>(11) Crankcase vents.</P>
                            <P>(h) * * *</P>
                            <P>(7) Equipment leaks from all components in gas service that are associated with a vapor recovery compressor, are not listed in paragraph (h)(1) or (2) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).</P>
                            <P>(8) Equipment leaks from all components in gas service that are not associated with a vapor recovery compressor, are not listed in paragraph (h)(1) or (2) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).</P>
                            <P>(9) Acid gas removal unit vents and nitrogen removal unit vents.</P>
                            <P>(10) Other large release events.</P>
                            <P>(11) Crankcase vents.</P>
                            <P>(i) * * *</P>
                            <P>(8) Other large release events.</P>
                            <P>(9) Blowdown vent stacks.</P>
                            <P>(10) Natural gas pneumatic device venting.</P>
                            <P>(11) Crankcase vents.</P>
                            <P>(j) * * *</P>
                            <P>(3) Acid gas removal unit vents and nitrogen removal unit vents.</P>
                            <STARS/>
                            <P>(6) Hydrocarbon liquids and produced water storage tank emissions.</P>
                            <STARS/>
                            <P>(10) Equipment leaks listed in paragraph (j)(10)(i) or (ii) of this section, as applicable:</P>
                            <P>
                                (i) Equipment leaks from components including valves, connectors, open ended lines, pressure relief valves, 
                                <PRTPAGE P="42223"/>
                                pumps, flanges, and other components (such as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breather caps, but does not include components in paragraph (j)(8) or (9) of this section, and it does not include thief hatches or other openings on a storage vessel).
                            </P>
                            <P>(ii) Equipment leaks from major equipment including wellheads, separators, meters/piping, compressors, dehydrators, heaters, and storage vessels.</P>
                            <STARS/>
                            <P>(13) Other large release events.</P>
                            <P>(14) Crankcase vents.</P>
                            <STARS/>
                            <P>
                                (m) For onshore natural gas transmission pipeline, report CO
                                <E T="52">2</E>
                                , CH
                                <E T="52">4</E>
                                , and N
                                <E T="52">2</E>
                                O emissions from the following source types:
                            </P>
                            <P>(1) Blowdown vent stacks.</P>
                            <P>(2) Other large release events.</P>
                            <P>(3) Equipment leaks listed in paragraph (m)(3)(i) or (ii) of this section, as applicable:</P>
                            <P>(i) Equipment leaks at transmission company interconnect metering-regulating stations.</P>
                            <P>(ii) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters at transmission company interconnect metering-regulating stations.</P>
                            <P>(4) Equipment leaks listed in paragraph (m)(4)(i) or (ii) of this section, as applicable:</P>
                            <P>(i) Equipment leaks at farm tap and/or direct sale metering-regulating stations.</P>
                            <P>(ii) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters at farm tap and/or direct sale metering-regulating stations.</P>
                            <P>(5) Transmission pipeline equipment leaks.</P>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>12. Effective July 15, 2024, amend § 98.233 by:</AMDPAR>
                        <AMDPAR>a. Revising paragraphs (a), (c), the first sentence of paragraph (d)(2), and (d)(4) introductory text;</AMDPAR>
                        <AMDPAR>b. Adding paragraph (d)(12);</AMDPAR>
                        <AMDPAR>c. Revising paragraphs (e) introductory text, (e)(1) introductory text, and (e)(2);</AMDPAR>
                        <AMDPAR>d. Revising paragraph (g) introductory text and (g)(1)(i);</AMDPAR>
                        <AMDPAR>
                            e. Revising parameter “FR
                            <E T="52">i,p</E>
                            ” of equation W-12B in paragraph (g)(1)(iv);
                        </AMDPAR>
                        <AMDPAR>f. Revising paragraph (i)(2)(i);</AMDPAR>
                        <AMDPAR>g. Revising paragraphs (j) introductory text, and (j)(2) introductory text and (j)(3);</AMDPAR>
                        <AMDPAR>h. Revising paragraphs (m)(1) through (3), (o)(10), (p)(10), (q) introductory text, (q)(1), and (q)(2) introductory text;</AMDPAR>
                        <AMDPAR>i. Adding paragraphs (q)(3) and (q)(4);</AMDPAR>
                        <AMDPAR>j. Revising paragraphs (s)(1) and (2) and (z)(1) introductory text;</AMDPAR>
                        <AMDPAR>k. Adding paragraph (z)(1)(iii); and</AMDPAR>
                        <AMDPAR>l. Revising paragraphs (z)(2) introductory text and (z)(2)(ii).</AMDPAR>
                        <P>The revisions and additions read as follows:</P>
                        <SECTION>
                            <SECTNO>§ 98.233</SECTNO>
                            <SUBJECT>Calculating GHG emissions.</SUBJECT>
                            <STARS/>
                            <P>
                                (a) 
                                <E T="03">Natural gas pneumatic device venting.</E>
                                 Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from natural gas pneumatic device venting using the applicable provisions as specified in this paragraph (a) of this section. If you have a continuous flow meter on the natural gas supply line dedicated to any one or combination of natural gas pneumatic devices or natural gas driven pneumatic pumps vented directly to the atmosphere for any portion of the year, you may use the method specified in paragraph (a)(1) of this section to calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from those devices. For natural gas pneumatic devices for which you do not elect to use Calculation Method 1, use the applicable methods specified in paragraphs (a)(2) through (7) of this section to calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions. All references to natural gas pneumatic devices for Calculation Method 1 in this paragraph (a) also apply to combinations of natural gas pneumatic devices and natural gas driven pneumatic pumps that are served by a common natural gas supply line. For Reporting Year 2024, you may use data collected anytime during the calendar year for any of the applicable calculation methods, provided that the data were collected in accordance with and meet the criteria of the applicable paragraphs (a)(1) through (4) of this section.
                            </P>
                            <P>
                                (1) 
                                <E T="03">Calculation Method 1.</E>
                                 If you have or elect to install a continuous flow meter that is capable of meeting the requirements of § 98.234(b) on the natural gas supply line dedicated to any one or combination of natural gas pneumatic devices and natural gas driven pneumatic pumps that are vented directly to the atmosphere, you may use the applicable methods specified in paragraphs (a)(1)(i) through (iv) of this section to calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from those devices.
                            </P>
                            <P>(i) For volumetric flow monitors:</P>
                            <P>
                                (A) Determine the cumulative annual volumetric flow, in standard cubic feet, as measured by the flow monitor in the reporting year. If all natural gas pneumatic devices supplied by the measured natural gas supply line are routed to the atmosphere for only a portion of the year and are routed to a flare, combustion, or vapor recovery system for the remaining portion of the year, determine the cumulative annual volumetric flow considering only those times when one or more of the natural gas pneumatic devices were vented directly to the atmosphere. If the flow meter was installed during the year, calculate the total volumetric flow for the year based on the measured volumetric flow times the total hours in the calendar year the devices were in service (
                                <E T="03">i.e.</E>
                                , supplied with natural gas) divided by the number of hours the devices were in service (
                                <E T="03">i.e.</E>
                                , supplied with natural gas) and the volumetric flow was being measured.
                            </P>
                            <P>
                                (B) Convert the natural gas volumetric flow from paragraph (a)(1)(i)(A) of this section to CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions following the provisions in paragraph (u) of this section.
                            </P>
                            <P>
                                (C) Convert the CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions from paragraph (a)(1)(i)(B) of this section to CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions using calculations in paragraph (v) of this section.
                            </P>
                            <P>(ii) For mass flow monitors:</P>
                            <P>
                                (A) Determine the cumulative annual mass flow, in metric tons, as measured by the flow monitor in the reporting year. If all natural gas pneumatic devices supplied by the measured natural gas supply line are vented directly to the atmosphere for only a portion of the year and are routed to a flare, combustion, or vapor recovery system for the remaining portion of the year, determine the cumulative annual mass flow considering only those times when one or more of the natural gas pneumatic devices were vented directly to the atmosphere. If the flow meter was installed during the year, calculate the total mass flow for the year based on the measured mass flow times the total hours in the calendar year the devices were in service (
                                <E T="03">i.e.</E>
                                , supplied with natural gas) divided by the number of hours the devices were in service (
                                <E T="03">i.e.</E>
                                , supplied with natural gas) and the mass flow was being measured.
                            </P>
                            <P>
                                (B) Convert the cumulative mass flow from paragraph (a)(1)(ii)(A) of this section to CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions by multiplying by the mass fraction of CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 in the supplied natural gas. You must follow the provisions in paragraph (u) of this section for determining the mole fraction of CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 and use molecular weights of 16 kg/kg-mol and 44 kg/kg-mol for CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                , respectively. You may assume unspecified components have an average molecular weight of 28 kg/kg-mol.
                            </P>
                            <P>
                                (iii) If the flow meter on the natural gas supply line serves both natural gas pneumatic devices and natural gas driven pneumatic pumps, disaggregate 
                                <PRTPAGE P="42224"/>
                                the total measured amount of natural gas to pneumatic devices and natural gas driven pneumatic pumps based on engineering calculations and best available data.
                            </P>
                            <P>(iv) The flow meter must be operated and calibrated according to the methods set forth in § 98.234(b).</P>
                            <P>
                                (2) 
                                <E T="03">Calculation Method 2.</E>
                                 Except as provided in paragraph (a)(1) of this section, you may elect to measure the volumetric flow rate of each natural gas pneumatic device vent that vents directly to the atmosphere at your well-pad site, gathering and boosting site, or facility, as applicable, as specified in paragraphs (a)(2)(i) through (ix) of this section. You must exclude the counts of devices measured according to paragraph (a)(1) of this section from the counts of devices to be measured or for which emissions are calculated according to the requirements in this paragraph (a)(2).
                            </P>
                            <P>(i) For facilities in the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments, you may elect to measure your pneumatic devices according to this Calculation Method 2 for some well-pad sites or gathering and boosting sites and use other methods for other sites. When you elect to measure the emissions from natural gas pneumatic devices according to this Calculation Method 2 at a well-pad site or gathering and boosting site, you must measure all natural gas pneumatic devices that are vented directly to the atmosphere at the well-pad site or gathering and boosting site during the same calendar year and you must measure and calculate emissions according to the provisions in paragraphs (a)(2)(iii) through (viii) of this section.</P>
                            <P>(ii) For facilities in the onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, or natural gas distribution industry segments electing to use this Calculation Method 2, you must measure all natural gas pneumatic devices vented directly to the atmosphere at your facility each year or, if your facility has 26 or more pneumatic devices, over multiple years, not to exceed the number of years as specified in paragraphs (a)(2)(ii)(A) through (D) of this section. If you elect to measure your pneumatic devices over multiple years, you must measure approximately the same number of devices each year. You must measure and calculate emissions for natural gas pneumatic devices at your facility according to the provisions in paragraphs (a)(2)(iii) through (ix), as applicable.</P>
                            <P>(A) If your facility has at least 26 but not more than 50 natural gas pneumatic devices vented directly to the atmosphere, the maximum number of years to measure all devices at your facility is 2 years.</P>
                            <P>(B) If your facility has at least 51 but not more than 75 natural gas pneumatic devices vented directly to the atmosphere, the maximum number of years to measure all devices at your facility is 3 years.</P>
                            <P>(C) If your facility has at least 76 but not more than 100 natural gas pneumatic devices vented directly to the atmosphere, the maximum number of years to measure all devices at your facility is 4 years.</P>
                            <P>(D) If your facility has 101 or more natural gas pneumatic devices vented directly to the atmosphere, the maximum number of years to measure all devices at your facility is 5 years.</P>
                            <P>(iii) For all industry segments, determine the volumetric flow rate of each natural gas pneumatic device vent (in standard cubic feet per hour) using one of the methods specified in § 98.234(b) through (d), as appropriate, according to the requirements specified in paragraphs (a)(2)(iii)(A) through (E) of this section. You must measure the emissions under conditions representative of normal operations, which excludes periods immediately after conducting maintenance on the device or manually actuating the device.</P>
                            <P>
                                (A) If you use a temporary meter, such as a vane anemometer, according to the methods set forth in § 98.234(b) or a high volume sampler according to methods set forth in § 98.234(d), you must measure the emissions from each device for a minimum of 15 minutes while the device is in service (
                                <E T="03">i.e.</E>
                                , supplied with natural gas), except for natural gas pneumatic isolation valve actuators. For natural gas pneumatic isolation valve actuators, you must measure the emissions from each device for a minimum of 5 minutes while the device is in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas). If there is no measurable flow from the natural gas pneumatic device after the minimum sampling period, you can discontinue monitoring and follow the applicable methods in paragraph (a)(2)(v) of this section.
                            </P>
                            <P>(B) If you use calibrated bagging, follow the methods set forth in § 98.234(c) except you need only fill one bag to have a valid measurement. You must collect sample for a minimum of 5 minutes for natural gas pneumatic isolation valve actuators or 15 minutes for other natural gas pneumatic devices. If no gas is collected in the calibrated bag during the minimum sampling period, you can discontinue monitoring and follow the applicable methods in paragraph (a)(2)(v) of this section. If gas is collected in the bag during the minimum sampling period, you must either continue sampling until you fill the calibrated bag or you may elect to remeasure the vent according to paragraph (a)(2)(iii)(A) of this section.</P>
                            <P>(C) You do not need to use the same measurement method for each natural gas pneumatic device vent.</P>
                            <P>(D) If the measurement method selected measures the volumetric flow rate in actual cubic feet, convert the measured flow to standard cubic feet following the methods specified in paragraph (t)(1) of this section.</P>
                            <P>(E) If there is measurable flow from the device vent, calculate the volumetric flow rate of each natural gas pneumatic device vent (in standard cubic feet per hour) by dividing the cumulative volume of natural gas measured during the measurement period (in standard cubic feet) by the duration of the measurement (in hours).</P>
                            <P>
                                (iv) For all industry segments, if there is measurable flow from the device vent, calculate the volume of natural gas emitted from each natural gas pneumatic device vent as the product of the natural gas flow rate measured in paragraph (a)(2)(iii) of this section and the number of hours the pneumatic device was in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) in the calendar year.
                            </P>
                            <P>(v) For all industry segments, if there is no measurable flow from the device vent, estimate the emissions from the device according to the methods in paragraphs (a)(2)(v)(A) through (C) of this section, as applicable.</P>
                            <P>(A) For continuous high bleed pneumatic devices:</P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) Confirm that the device is in-service. If not, remeasure the device according to paragraph (a)(2)(iii) of this section at a time the device is in-service and calculate natural gas emissions from the device according to paragraph (a)(2)(iv) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) Confirm that the device is correctly characterized as a continuous high bleed pneumatic device according to the provisions in paragraph (a)(7) of this section. If the device type was mischaracterized, recharacterize the device type and use the appropriate methods in paragraph (a)(2)(v)(B) or (C) of this section, as applicable.
                            </P>
                            <P>
                                (
                                <E T="03">3</E>
                                ) Upon confirmation of the items in paragraphs (a)(2)(v)(A)(
                                <E T="03">1</E>
                                ) and (
                                <E T="03">2</E>
                                ) of this section, remeasure the device vent using a different measurement method specified in § 98.234(b) through (d) or longer monitoring duration until there is a measurable flow from the device and calculate the natural gas emissions from 
                                <PRTPAGE P="42225"/>
                                the device according to paragraph (a)(2)(iv) of this section.
                            </P>
                            <P>(B) For continuous low bleed pneumatic devices:</P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) Confirm that the device is in-service. If not, remeasure the device according to paragraph (a)(2)(iii) of this section at a time the device is in-service and calculate natural gas emissions from the device according to paragraph (a)(2)(iv) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) Determine natural gas bleed rate (in standard cubic feet per hour) at the supply pressure used for the pneumatic device based on the manufacturer's steady state natural gas bleed rate reported for the device. If the steady state bleed rate is reported in terms of air consumption, multiply the air consumption rate by 1.29 to calculate the steady state natural gas bleed rate. If a steady state bleed rate is not reported, follow the requirements in paragraph (a)(2)(v)(B)(
                                <E T="03">4</E>
                                ) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">3</E>
                                ) Calculate the volume of natural gas emitted from the natural gas pneumatic device vent as the product of the natural gas steady state bleed rate determined in paragraph (a)(2)(v)(B)(2) of this section and number of hours the pneumatic device was in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) in the calendar year.
                            </P>
                            <P>
                                (
                                <E T="03">4</E>
                                ) If a steady state bleed rate is not reported, reassess whether the device is correctly characterized as a continuous low bleed pneumatic device according to the provisions in paragraph (a)(7) of this section. If the device is confirmed to be a continuous low bleed pneumatic device, you must remeasure the device vent using a different measurement method specified in § 98.234(b) through (d) or longer monitoring duration until there is a measurable flow from the device and calculate natural gas emissions from the device according to paragraph (a)(2)(iv) of this section. If the device type was mischaracterized, recharacterize the device type and use the appropriate methods in paragraph (a)(2)(v)(A) or (C) of this section, as applicable.
                            </P>
                            <P>(C) For intermittent bleed pneumatic devices:</P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) Confirm that the device is in-service. If not, remeasure the device according to paragraph (a)(2)(iii) of this section at a time the device is in-service and calculate natural gas emissions according to paragraph (a)(2)(iv) of this section. For devices confirmed to be in-service during the measurement period, calculate natural gas emissions according to paragraphs (a)(2)(v)(C)(
                                <E T="03">2</E>
                                ) through (
                                <E T="03">5</E>
                                ) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) Calculate the volume of the controller, tubing and actuator (in actual cubic feet) based on the device and tubing size.
                            </P>
                            <P>
                                (
                                <E T="03">3</E>
                                ) Sum the volumes in paragraph (a)(2)(v)(C)(
                                <E T="03">2</E>
                                ) of this section and convert the volume to standard cubic feet following the methods specified in paragraph (t)(1) of this section based on the natural gas supply pressure.
                            </P>
                            <P>
                                (
                                <E T="03">4</E>
                                ) Estimate the number of actuations during the year based on company records, if available, or best engineering estimates. For isolation valve actuators, you may multiply the number of valve closures during the year by 2 (one actuation to close the valve; one actuation to open the valve).
                            </P>
                            <P>
                                (
                                <E T="03">5</E>
                                ) Calculate the volume of natural gas emitted from the natural gas pneumatic device vent as the product of the per actuation volume in standard cubic feet determined in paragraph (a)(2)(v)(C)(
                                <E T="03">3</E>
                                ) of this section, the number of actuations during the year as determined in paragraph (a)(2)(v)(C)(
                                <E T="03">4</E>
                                ) of this section, and the relay correction factor. Use 1 for the relay correction factor if there is no relay; use 3 for the relay correction factor if there is a relay.
                            </P>
                            <P>
                                (vi) For each pneumatic device, convert the volumetric emissions of natural gas at standard conditions determined in paragraph (a)(2)(iv) or (v) of this section, as applicable, to CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 volumetric emissions at standard conditions using the methods specified in paragraph (u) of this section.
                            </P>
                            <P>(vii) For each pneumatic device, convert the GHG volumetric emissions at standard conditions determined in paragraph (a)(2)(vi) of this section to GHG mass emissions using the methods specified in paragraph (v) of this section.</P>
                            <P>
                                (viii) Sum the CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 mass emissions determined in paragraph (a)(2)(vii) of this section separately for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed).
                            </P>
                            <P>(ix) For facilities in the onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, or natural gas distribution industry segments, if you chose to conduct natural gas pneumatic device measurements over multiple years, “n,” according to paragraph (a)(2)(ii) of this section, then you must calculate the emissions from all pneumatic devices at your facility as specified in paragraph (a)(2)(ix)(A) through (E) of this section.</P>
                            <P>(A) Use the emissions calculated in (a)(2)(viii) of this section for the devices measured during the reporting year.</P>
                            <P>
                                (B) Calculate the whole gas emission factor for each type of pneumatic device at the facility using equation W-1A to this section and all available data from the current year and the previous years in your monitoring cycle (n-1 years) for which natural gas pneumatic device vent measurements were made according to Calculation Method 2 in paragraph (a)(2) of this section (
                                <E T="03">e.g.,</E>
                                 if your monitoring cycle is 3 years, then use measured data from the current year and the two previous years). This emission factor must be updated annually.
                            </P>
                            <GPH SPAN="3" DEEP="37">
                                <GID>ER14MY24.024</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">t</E>
                                     = Whole gas population emission factor for natural gas pneumatic device vents of type “t” (continuous high bleed, continuous low bleed, intermittent bleed), in standard cubic feet per hour per device.
                                </FP>
                                <FP SOURCE="FP-2">
                                    MT
                                    <E T="52">s,t,y</E>
                                     = Volumetric whole gas emissions rate measurement at standard (“s”) conditions from component type “t” during year “y” in standard cubic feet per hour, as calculated in paragraph (a)(2)(iii) [if there was measurable flow from the device vent], (a)(2)(v)(B)(
                                    <E T="03">2</E>
                                    ), or (a)(2)(v)(C)(
                                    <E T="03">6</E>
                                    ) of this section, as applicable.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Count
                                    <E T="52">t,y</E>
                                     = Count of natural gas pneumatic device vents of type “t” measured according to Calculation Method 2 in year “y.”
                                </FP>
                                <FP SOURCE="FP-2">n = Number of years of data to include in the emission factor calculation according to the number of years used to monitor all natural gas pneumatic device vents at the facility.</FP>
                            </EXTRACT>
                            <P>
                                (C) Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions from continuous high bleed, continuous low bleed, and intermittent bleed natural gas pneumatic devices that were not measured during the reporting year using equation W-1B to this section.
                            </P>
                            <GPH SPAN="3" DEEP="32">
                                <PRTPAGE P="42226"/>
                                <GID>ER14MY24.025</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i</E>
                                     = Annual total volumetric GHG emissions at standard conditions in standard cubic feet per year from natural gas pneumatic device vents, of types “t” (continuous high bleed, continuous low bleed, intermittent bleed), for GHG
                                    <E T="52">i</E>
                                    .
                                </FP>
                                <FP SOURCE="FP-2">
                                    Count
                                    <E T="52">t</E>
                                     = Total number of natural gas pneumatic devices of type “t” (continuous high bleed, continuous low bleed, intermittent bleed) as determined in paragraphs (a)(5) through (7) of this section that vent directly to the atmosphere and that were not directly measured according to the requirements in paragraph (a)(1) or (a)(2)(iii) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">t</E>
                                     = Population emission factors for natural gas pneumatic device vents (in standard cubic feet per hour per device) of each type “t” (continuous high bleed, continuous low bleed, intermittent bleed) as calculated using equation W-1A to this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i</E>
                                     = Concentration of GHG
                                    <E T="52">i</E>
                                    , CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    , in produced natural gas or processed natural gas for each facility as specified in paragraph (u)(2) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">t</E>
                                     = Average estimated number of hours in the operating year the devices, of each type “t”, were in service (
                                    <E T="03">i.e.,</E>
                                     supplied with natural gas) using engineering estimates based on best available data. Default is 8,760 hours.
                                </FP>
                            </EXTRACT>
                            <P>
                                (D) Convert the volumetric emissions calculated using equation W-1B to this section to CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions using the methods specified in paragraph (v) of this section.
                            </P>
                            <P>
                                (E) Sum the CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions calculated in paragraphs (a)(2)(ix)(A) and (D) of this section separately for each type of pneumatic device (continuous high bleed, continuous low bleed, intermittent bleed) to calculate the total CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions by device type for Calculation Method 2.
                            </P>
                            <P>
                                (3) 
                                <E T="03">Calculation Method 3.</E>
                                 For facilities in the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments, you may elect to use the applicable methods specified in paragraphs (a)(3)(i) through (iv) of this section, as applicable, to calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from your natural gas pneumatic devices that are vented directly to the atmosphere at your site except those that are measured according to paragraph (a)(1) or (2) of this section. You must exclude the counts of devices measured according to paragraph (a)(1) of this section from the counts of devices to be monitored or for which emissions are calculated according to the requirements in this paragraph (a)(3). You may not use this Calculation Method 3 for those well-pad sites or gathering and boosting sites for which you elected to measure emissions according to paragraph (a)(2) of this section.
                            </P>
                            <P>
                                (i) For continuous high bleed and continuous low bleed natural gas pneumatic devices vented directly to the atmosphere, you must calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions using either the methods in paragraph (a)(3)(i)(A) or (B) of this section.
                            </P>
                            <P>(A) Measure all continuous high bleed and continuous low bleed pneumatic devices at your well-pad site or gathering and boosting site, as applicable, according to the provisions in paragraphs (a)(2) of this section.</P>
                            <P>(B) Use equation W-1B to this section, except use the appropriate default whole gas population emission factors for natural gas pneumatic device vents (in standard cubic feet per hour per device) of each type “t” (continuous high bleed and continuous low bleed) as listed in table W-1A to this subpart.</P>
                            <P>(ii) For intermittent bleed pneumatic devices, monitor each intermittent bleed pneumatic device at your well-pad site or gathering and boosting site as specified in paragraphs (a)(3)(ii)(A) through (C) of this section, as applicable.</P>
                            <P>(A) You must use one of the monitoring methods specified in § 98.234(a)(1) through (3) except that the monitoring dwell time for each device vent must be at least 2 minutes or until a malfunction is identified, whichever is shorter. A device is considered malfunctioning if any leak is observed when the device is not actuating or if a leak is observed for more than 5 seconds, or the extended duration as specified in paragraph (a)(3)(ii)(C) of this section if applicable, during a device actuation. If you cannot tell when a device is actuating, any observed leak from the device indicates a malfunctioning device.</P>
                            <P>(B) If you elect to monitor emissions from natural gas pneumatic devices at a well-pad site or gathering and boosting site according to this Calculation Method 3, you must monitor all natural gas intermittent bleed pneumatic devices that are vented directly to the atmosphere at the well-pad site or gathering and boosting site during the same calendar year. You must monitor the natural gas intermittent bleed pneumatic devices under conditions representative of normal operations, which excludes periods immediately after conducting maintenance on the device or manually actuating the device.</P>
                            <P>
                                (C) For certain throttling pneumatic devices or isolation valve actuators on pipes greater than 5 inches in diameter, that may actuate for more than 5 seconds under normal conditions, you may elect to identify individual devices for which longer bleed periods may be allowed as specified in paragraphs (a)(3)(ii)(C)(
                                <E T="03">1</E>
                                ) and (
                                <E T="03">2</E>
                                ) of this section prior to monitoring these devices for the first time.
                            </P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) You must identify the devices for which extended actuations are considered normal operations. For each device identified, you must determine the typical actuation time and maintain documentation and rationale for the extended actuation duration value.
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) You must clearly and permanently tag the device vent for each natural gas pneumatic device that has an extended actuation duration. The tag must include the device ID and the normal duration period (in seconds) as determined and documented for the device as specified in paragraph (a)(3)(ii)(C)(
                                <E T="03">1</E>
                                ) of this section.
                            </P>
                            <P>
                                (iii) For intermittent bleed pneumatic devices that are monitored according to paragraph (a)(3)(ii) of this section during the reporting year, you must calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions from intermittent bleed natural gas pneumatic devices vented directly to the atmosphere using equation W-1C to this section.
                            </P>
                            <GPH SPAN="3" DEEP="37">
                                <GID>ER14MY24.026</GID>
                            </GPH>
                            <EXTRACT>
                                <PRTPAGE P="42227"/>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">i</E>
                                     = Annual total volumetric emissions of GHG
                                    <E T="52">i</E>
                                     from intermittent bleed natural gas pneumatic devices in standard cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i</E>
                                     = Concentration of GHG
                                    <E T="52">i</E>
                                    , CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    , in natural gas supplied to the intermittent bleed natural gas pneumatic device as defined in paragraph (u)(2) of this section.
                                </FP>
                                <FP SOURCE="FP-2">x = Total number of intermittent bleed natural gas pneumatic devices detected as malfunctioning in any pneumatic device monitoring survey during the year. A component found as malfunctioning in two or more surveys during the year is counted as one malfunctioning component.</FP>
                                <FP SOURCE="FP-2">
                                    K
                                    <E T="52">1</E>
                                     = Whole gas emission factor for malfunctioning intermittent bleed natural gas pneumatic devices, in standard cubic feet per hour per device. Use 24.1 for well-pad sites in the onshore petroleum and natural gas production industry segment and use 16.1 for gathering and boosting sites in the onshore petroleum and natural gas gathering and boosting industry segment.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">mal,z</E>
                                     = The total time the surveyed pneumatic device “z” was in service (
                                    <E T="03">i.e.,</E>
                                     supplied with natural gas) and assumed to be malfunctioning, in hours. If one pneumatic device monitoring survey is conducted in the calendar year, assume the device found malfunctioning was malfunctioning for the entire calendar year. If multiple pneumatic device monitoring surveys are conducted in the calendar year, assume a device found malfunctioning in the first survey was malfunctioning since the beginning of the year until the date of the survey; assume a device found malfunctioning in the last survey of the year was malfunctioning from the preceding survey through the end of the year; assume a device found malfunctioning in a survey between the first and last surveys of the year was malfunctioning since the preceding survey until the date of the survey; and sum times for all malfunctioning periods.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">t,z</E>
                                     = The total time the surveyed natural gas pneumatic device “z” was in service (
                                    <E T="03">i.e.,</E>
                                     supplied with natural gas) during the year. Default is 8,760 hours for non-leap years and 8,784 hours for leap years.
                                </FP>
                                <FP SOURCE="FP-2">
                                    K
                                    <E T="52">2</E>
                                     = Whole gas emission factor for properly operating intermittent bleed natural gas pneumatic devices, in standard cubic feet per hour per device. Use 0.3 for well-pad sites in the onshore petroleum and natural gas production industry segment and use 2.8 for gathering and boosting sites in the onshore petroleum and natural gas gathering and boosting industry segment.
                                </FP>
                                <FP SOURCE="FP-2">Count = Total number of intermittent bleed natural gas pneumatic devices that were never observed to be malfunctioning during any monitoring survey during the year.</FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">avg</E>
                                     = The average time the intermittent bleed natural gas pneumatic devices that were never observed to be malfunctioning during any monitoring survey were in service (
                                    <E T="03">i.e.,</E>
                                     supplied with natural gas) using engineering estimates based on best available data. Default is 8,760 hours for non-leap years and 8,784 hours for leap years.
                                </FP>
                            </EXTRACT>
                            <P>(A) You must conduct at least one complete pneumatic device monitoring survey in a calendar year. If you conduct multiple complete pneumatic device monitoring surveys in a calendar year, you must use the results from each complete pneumatic device monitoring survey when calculating emissions using equation W-1C to this section.</P>
                            <P>(B) For the purposes of paragraph (a)(3)(iii)(A) of this section, a complete monitoring survey is a survey of all intermittent bleed natural gas pneumatic devices vented directly to the atmosphere at a well-pad site for onshore petroleum and natural gas production facilities (except those measured according to paragraph (a)(1) of this section) or all intermittent bleed pneumatic devices vented directly to the atmosphere at a gathering and boosting site for onshore petroleum and natural gas gathering and boosting facilities (except those measured according to paragraph (a)(1) of this section).</P>
                            <P>
                                (iv) You must convert the CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions as determined according to paragraphs (a)(3)(i) and (iii) of this section and calculate both CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 mass emissions using calculations in paragraph (v) of this section for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed).
                            </P>
                            <P>
                                (4) 
                                <E T="03">Calculation Method 4.</E>
                                 You may elect to calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from your natural gas pneumatic devices at your facility using the methods specified in paragraphs (a)(4)(i) and (ii) of this section except those that are measured according to paragraphs (a)(1) through (3) of this section. You must exclude the counts of devices measured according to paragraph (a)(1) of this section from the counts of devices to be monitored or for which emissions are calculated according to the requirements in this paragraph (a)(4). You may not use this Calculation Method 4 for those devices for which you elected to measure emissions according to paragraph (a)(1), (2), or (3) of this section.
                            </P>
                            <P>
                                (i) You must calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions using equation W-1B to this section, except use the appropriate default whole gas population emission factors for natural gas pneumatic device vents (in standard cubic feet per hour per device) of each type “t” (continuous high bleed, continuous low bleed, and intermittent bleed) listed in table W-1A to this subpart for onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities, table W-3B to this subpart for onshore natural gas transmission compression facilities, and table W-4B to this subpart for underground natural gas storage facilities.
                            </P>
                            <P>
                                (ii) You must convert the CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions as determined according to paragraphs (a)(4)(i) of this section and calculate both CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 mass emissions using calculations in paragraph (v) of this section for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed).
                            </P>
                            <P>
                                (5) 
                                <E T="03">Counts of natural gas pneumatic devices.</E>
                                 For all industry segments, determine “Countt” for equation W-1A, W-1B, or W-1C to this section for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed) by counting the total number of devices at the well-pad site, gathering and boosting site, or facility, as applicable, the number of devices that are vented directly to the atmosphere and the number of those devices that were measured or monitored during the reporting year, as applicable, except as specified in paragraph (a)(6) of this section.
                            </P>
                            <P>
                                (6) 
                                <E T="03">Counts of onshore petroleum and natural gas production industry segment or the onshore petroleum and natural gas gathering and boosting natural gas pneumatic devices.</E>
                                 For facilities in the onshore petroleum and natural gas production industry segment or the onshore petroleum and natural gas gathering and boosting industry segment, you have the option in the first two consecutive calendar years to determine the total number of natural gas pneumatic devices at the facility and the number of devices that are vented directly to the atmosphere for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed), as applicable, using engineering estimates based on best available data. Counts of natural gas pneumatic devices measured or monitored during the reporting year must be made based on actual counts.
                            </P>
                            <P>
                                (7) 
                                <E T="03">Type of natural gas pneumatic devices.</E>
                                 For all industry segments, determine the type of natural gas pneumatic device using engineering estimates based on best available information.
                            </P>
                            <STARS/>
                            <P>
                                (c) 
                                <E T="03">Natural gas driven pneumatic pump venting.</E>
                                 Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                  
                                <PRTPAGE P="42228"/>
                                emissions from natural gas driven pneumatic pumps as specified in paragraph (c)(1), (2), or (3) of this section, as applicable. If you have a continuous flow meter on the natural gas supply line that is dedicated to any one or more natural gas driven pneumatic pumps, each of which only vents directly to the atmosphere, you may use Calculation Method 1 as specified in paragraph (c)(1) of this section to calculate vented CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from those pumps. You may use Calculation Method 1 for any portion of a year when all of the pumps on the continuously measured natural gas supply line were vented directly to atmosphere. For natural gas driven pneumatic pumps for which you do not elect to use Calculation Method 1, use either the method specified in paragraph (c)(2) or (3) of this section to calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions; you may not use Calculation Method 2 for some vented natural gas driven pneumatic pumps and Calculation Method 3 for other natural gas driven pneumatic pumps. All references to natural gas driven pneumatic pumps for Calculation Method 1 in this paragraph (c) also apply to combinations of natural gas pneumatic devices and natural gas driven pneumatic pumps that are served by a common natural gas supply line. You do not have to calculate emissions from natural gas driven pneumatic pumps covered in paragraph (e) of this section under this paragraph (c). For Reporting Year 2024, you may use data collected anytime during the calendar year for any of the applicable calculation methods, provided that the data were collected in accordance with and meet the criteria of the applicable paragraphs (c)(1) through (3) of this section.
                            </P>
                            <P>
                                (1) 
                                <E T="03">Calculation Method 1.</E>
                                 If you have or elect to install a continuous flow meter that is capable of meeting the requirements of § 98.234(b) on a supply line to natural gas driven pneumatic pumps, then for the period of the year when the natural gas supply line is dedicated to any one or more natural gas driven pneumatic pumps, and each of the pumps is vented directly to the atmosphere, you may use the applicable methods specified in paragraphs (c)(1)(i) or (ii) of this section to calculate vented CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from those pumps.
                            </P>
                            <P>(i) For volumetric flow monitors:</P>
                            <P>(A) Determine the cumulative annual volumetric flow, in standard cubic feet, as measured by the flow monitor in the reporting year. If the flow meter was installed during the year, calculate the total volumetric flow for the year based on the measured volumetric flow times the total hours in the calendar year in which at least one of the pumps connected to the supply line was pumping liquid divided by the number of hours in the year when at least one of pumps connected to the supply line was pumping liquid and the volumetric flow was being measured.</P>
                            <P>
                                (B) Convert the natural gas volumetric flow from paragraph (c)(1)(i)(A) of this section to CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions following the provisions in paragraph (u) of this section.
                            </P>
                            <P>
                                (C) Convert the CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions from paragraph (c)(1)(i)(B) of this section to CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions using calculations in paragraph (v) of this section.
                            </P>
                            <P>(ii) For mass flow monitors:</P>
                            <P>(A) Determine the cumulative annual mass flow, in metric tons, as measured by the flow monitor in the reporting year. If the flow meter was installed during the year, calculate the total mass flow of vented natural gas emissions for the year based on the measured mass flow times the total hours in the calendar year in which at least one of the pumps connected to the supply line was pumping liquid divided by the number of hours in the year when at least one of pumps connected to the supply line was pumping liquid and the mass flow was being measured.</P>
                            <P>
                                (B) Convert the cumulative mass flow from paragraph (c)(1)(ii)(A) of this section to CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions by multiplying by the mass fraction of CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 in the supplied natural gas. You must follow the provisions in paragraph (u) of this section for determining the mole fraction of CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 and use molecular weights of 16 kg/kg-mol and 44 kg/kg-mol for CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                , respectively. You may assume unspecified components have an average molecular weight of 28 kg/kg-mol.
                            </P>
                            <P>(iii) If the supply line serves both natural gas pneumatic devices and natural gas driven pneumatic pumps, disaggregate the total measured amount of natural gas to natural gas pneumatic devices and natural gas driven pneumatic pumps based on engineering calculations and best available data.</P>
                            <P>(iv) The flow meter must be operated and calibrated according to the methods set forth in § 98.234(b).</P>
                            <P>
                                (2) 
                                <E T="03">Calculation Method 2.</E>
                                 Except as provided in paragraph (c)(1) of this section, you may elect to measure the volumetric flow rate of each natural gas driven pneumatic pump at your facility that vents directly to the atmosphere as specified in paragraphs (c)(2)(i) through (vii) of this section. You must exclude the counts of pumps measured according to paragraph (c)(1) of this section from the counts of pumps to be measured and for which emissions are calculated according to the requirements in this paragraph (c)(2).
                            </P>
                            <P>(i) Measure all natural gas driven pneumatic pumps at your facility at least once every 5 years. If you elect to measure your pneumatic pumps over multiple years, you must measure approximately the same number of pumps each year. When you measure the emissions from natural gas driven pneumatic pumps at a well-pad site or gathering and boosting site, you must measure all pneumatic pumps that are vented directly to the atmosphere at the well-pad site or gathering and boosting site during the same calendar year.</P>
                            <P>(ii) Determine the volumetric flow rate of each natural gas driven pneumatic pump (in standard cubic feet per hour) using one of the methods specified in § 98.234(b) through (d), as appropriate, according to the requirements specified in paragraphs (c)(2)(ii)(A) through (D) of this section. You must measure the emissions under conditions representative of normal operations, which excludes periods immediately after conducting maintenance on the pump.</P>
                            <P>(A) If you use a temporary meter, such as a vane anemometer, according to the methods set forth in § 98.234(b) or a high volume sampler according to methods set forth in § 98.234(d), you must measure the emissions from each pump for a minimum of 5 minutes, during a period when the pump is continuously pumping liquid.</P>
                            <P>(B) If you use calibrated bagging, follow the methods set forth in § 98.234(c), except under § 98.234(c)(2), only one bag must be filled to have a valid measurement. You must collect sample for a minimum of 5 minutes, or until the bag is full, whichever is shorter, during a period when the pump is continuously pumping liquid. If the bag is not full after 5 minutes, you must either continue sampling until you fill the calibrated bag or you may elect to remeasure the vent according to paragraph (c)(2)(ii)(A) of this section.</P>
                            <P>(C) You do not need to use the same measurement method for each natural gas driven pneumatic pump vent.</P>
                            <P>(D) If the measurement method selected measures the volumetric flow rate in actual cubic feet, convert the measured flow to standard cubic feet following the methods specified in paragraph (t)(1) of this section. Convert the measured flow during the test period to standard cubic feet per hour, as appropriate.</P>
                            <P>
                                (iii) Calculate the volume of natural gas emitted from each natural gas driven pneumatic pump vent as the product of 
                                <PRTPAGE P="42229"/>
                                the natural gas emissions flow rate measured in paragraph (c)(2)(ii) of this section and the number of hours that liquid was pumped by the pneumatic pump in the calendar year.
                            </P>
                            <P>
                                (iv) For each pneumatic pump, convert the volumetric emissions of natural gas at standard conditions determined in paragraph (c)(2)(iii) of this section to CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 volumetric emissions at standard conditions using the methods specified in paragraph (u) of this section.
                            </P>
                            <P>(v) For each pneumatic pump, convert the GHG volumetric emissions at standard conditions determined in paragraph (c)(2)(iv) of this section to GHG mass emissions using the methods specified in paragraph (v) of this section.</P>
                            <P>
                                (vi) Sum the CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 mass emissions determined in paragraph (c)(2)(v) of this section.
                            </P>
                            <P>(vii) If you chose to conduct natural gas pneumatic pump measurements over multiple years, “n,” according to paragraph (c)(2)(i) of this section, then you must calculate the emissions from all pneumatic pumps at your facility as specified in paragraph (c)(2)(vii)(A) through (D) of this section.</P>
                            <P>(A) Use the emissions calculated in paragraph (c)(2)(vi) of this section for the pumps measured during the reporting year.</P>
                            <P>
                                (B) Calculate the whole gas emission factor for pneumatic pumps at the facility using equation W-2A to this section and all available data from the current year and the previous years in your monitoring cycle (n-1 years) for which natural gas pneumatic pump vent measurements were made according to Calculation Method 2 in paragraph (c)(2) of this section (
                                <E T="03">e.g.,</E>
                                 if your monitoring cycle is 3 years, then use measured data from the current year and the two previous years). This emission factor must be updated annually.
                            </P>
                            <GPH SPAN="3" DEEP="34">
                                <GID>ER14MY24.027</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">s</E>
                                     = Whole gas population emission factor for natural gas pneumatic pump vents, in standard cubic feet per hour per pump.
                                </FP>
                                <FP SOURCE="FP-2">
                                    MT
                                    <E T="52">s,y</E>
                                     = Volumetric whole gas emissions rate measurement at standard (“s”) conditions during year “y” in standard cubic feet per hour, as calculated in paragraph (c)(2)(iii) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Count
                                    <E T="52">y</E>
                                     = Count of natural gas driven pneumatic pump vents measured according to Calculation Method 2 in year “y.”
                                </FP>
                                <FP SOURCE="FP-2">n = Number of years of data to include in the emission factor calculation according to the number of years used to monitor all natural gas pneumatic pump vents at the facility.</FP>
                            </EXTRACT>
                            <P>
                                (C) Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions from natural gas driven pneumatic pumps that were not measured during the reporting year using equation W-2B to this section.
                            </P>
                            <GPH SPAN="3" DEEP="14">
                                <GID>ER14MY24.028</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i</E>
                                     = Annual total volumetric GHG emissions at standard conditions in standard cubic feet per year from natural gas driven pneumatic pump vents, for GHG
                                    <E T="52">i</E>
                                    .
                                </FP>
                                <FP SOURCE="FP-2">Count = Total number of natural gas driven pneumatic pumps that vented directly to the atmosphere and that were not directly measured according to the requirements in paragraphs (c)(1) or (c)(2)(ii) of this section.</FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">s</E>
                                     = Population emission factors for natural gas driven pneumatic pumps (in standard cubic feet per hour per pump) as calculated using equation W-2A to this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i</E>
                                     = Concentration of GHG
                                    <E T="52">i</E>
                                    , CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    , in produced natural gas as defined in paragraph (u)(2)(i) of this section.
                                </FP>
                                <FP SOURCE="FP-2">T = Average estimated number of hours in the operating year the pumps that vented directly to the atmosphere were pumping liquid using engineering estimates based on best available data. Default is 8,760 hours for pumps that only vented directly to the atmosphere.</FP>
                            </EXTRACT>
                            <P>
                                (D) Calculate both CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions from volumetric emissions calculated using equation W-2B to this section using calculations in paragraph (v) of this section.
                            </P>
                            <P>
                                (E) Sum the CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions calculated in paragraphs (c)(2)(vii)(A) and (D) of this section to calculate the total CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions for Calculation Method 2.
                            </P>
                            <P>
                                (3) 
                                <E T="03">Calculation Method 3.</E>
                                 If you elect not to measure emissions as specified in Calculation Method 2, then you must use the applicable method specified in paragraphs (c)(3)(i) and (ii) of this section to calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from all natural gas driven pneumatic pumps that are vented directly to the atmosphere at your facility and that are not measured according to paragraph (c)(1) of this section. You must exclude the counts of devices measured according to paragraph (c)(1) of this section from the counts of pumps for which emissions are calculated according to the requirements in this paragraph (c)(3).
                            </P>
                            <P>
                                (i) Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions from natural gas driven pneumatic pumps using equation W-2B to this section, except use the appropriate default whole gas population emission factor for natural gas pneumatic pump vents (in standard cubic feet per hour per device) as provided in table W-1A to this subpart.
                            </P>
                            <P>
                                (ii) Convert the CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions determined according to paragraph (c)(3)(i) of this section to CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 mass emissions using calculations in paragraph (v) of this section.
                            </P>
                            <P>(d) * * *</P>
                            <P>
                                (2) 
                                <E T="03">Calculation Method 2.</E>
                                 Except as specified in paragraph (d)(4) of this section, if a CEMS is not available but a vent meter is installed, use the CO
                                <E T="52">2</E>
                                 composition and annual volume of vent gas to calculate emissions using equation W-3 to this section.
                            </P>
                            <STARS/>
                            <P>
                                (4) 
                                <E T="03">Calculation Method 4.</E>
                                 If CEMS or a vent meter is not installed, you may calculate emissions using any standard simulation software package, such as AspenTech HYSYS®, or API 4679 AMINECalc, that uses the Peng-Robinson equation of state and speciates CO
                                <E T="52">2</E>
                                 emissions. You may also use this method if a vent meter is installed but a CEMS is not, in which case you must determine the difference between the annual volume of vent gas measured by the vent meter and the simulated annual volume of vent gas according to paragraph (d)(12) of this section. A minimum of the following, determined for typical operating conditions over the calendar year by engineering estimate and process knowledge based on best 
                                <PRTPAGE P="42230"/>
                                available data, must be used to characterize emissions:
                            </P>
                            <STARS/>
                            <P>
                                (12) 
                                <E T="03">Comparison of annual volume of vent gas.</E>
                                 If a vent meter is installed but you wish to use Calculation Method 4 rather than Calculation Method 2 for an AGR, use equation W-4D to this section to determine the difference between the annual volume of vent gas measured by the vent meter and the simulated annual volume of vent gas.
                            </P>
                            <GPH SPAN="3" DEEP="39">
                                <GID>ER14MY24.029</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">PD = Percent difference between vent gas volumes, %.</FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">a,meter</E>
                                     = Total annual volume of vent gas flowing out of the AGR in cubic feet per year at actual conditions as determined by flow meter using methods set forth in § 98.234(b). Alternatively, you may follow the manufacturer's instructions or industry standard practice for calibration of the vent meter.
                                </FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">a,sim</E>
                                     = Total annual volume of vent gas flowing out of the AGR in cubic feet per year at actual conditions as determined by a standard simulation software package consistent with paragraph (d)(4) of this section.
                                </FP>
                            </EXTRACT>
                            <P>
                                (e) 
                                <E T="03">Dehydrator vents.</E>
                                 For dehydrator vents, calculate annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions using the applicable calculation methods described in paragraphs (e)(1) through (e)(4) of this section. For glycol dehydrators that have an annual average daily natural gas throughput that is greater than or equal to 0.4 million standard cubic feet per day, use Calculation Method 1 in paragraph (e)(1) of this section. For glycol dehydrators that have an annual average of daily natural gas throughput that is greater than 0 million standard cubic feet per day and less than 0.4 million standard cubic feet per day, use either Calculation Method 1 in paragraph (e)(1) of this section or Calculation Method 2 in paragraph (e)(2) of this section. If emissions from dehydrator vents are routed to a vapor recovery system, you must adjust the emissions downward according to paragraph (e)(5) of this section. If emissions from dehydrator vents are routed to a flare or regenerator fire-box/fire tubes, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O annual emissions as specified in paragraph (e)(6) of this section. For Reporting Year 2024, you may use data collected anytime during the calendar year for any of the applicable calculation methods, provided that the data were collected in accordance with and meet the criteria of the applicable paragraphs (e)(1) through (3) of this section.
                            </P>
                            <P>
                                (1) 
                                <E T="03">Calculation Method 1.</E>
                                 Calculate annual mass emissions from glycol dehydrators by using a software program, such as AspenTech HYSYS® or GRI-GLYCalc
                                <E T="51">TM</E>
                                , that uses the Peng-Robinson equation of state to calculate the equilibrium coefficient, speciates CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from dehydrators, and has provisions to include regenerator control devices, a separator flash tank, stripping gas and a gas injection pump or gas assist pump. The following parameters must be determined by engineering estimate based on best available data and must be used at a minimum to characterize emissions from dehydrators:
                            </P>
                            <STARS/>
                            <P>
                                (2) 
                                <E T="03">Calculation Method 2.</E>
                                 Calculate annual volumetric emissions from glycol dehydrators using equation W-5 to this section:
                            </P>
                            <GPH SPAN="3" DEEP="24">
                                <GID>ER14MY24.030</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i</E>
                                     = Annual total volumetric GHG emissions (either CO
                                    <E T="52">2</E>
                                     or CH
                                    <E T="52">4</E>
                                    ) at standard conditions in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">i</E>
                                     = Population emission factors for glycol dehydrators in thousand standard cubic feet per dehydrator per year. Use 73.4 for CH
                                    <E T="52">4</E>
                                     and 3.21 for CO
                                    <E T="52">2</E>
                                     at 60 °F and 14.7 psia.
                                </FP>
                                <FP SOURCE="FP-2">Count = Total number of glycol dehydrators that have an annual average daily natural gas throughput that is less than 0.4 million standard cubic feet per day for which you elect to use this Calculation Method 2.</FP>
                                <FP SOURCE="FP-2">
                                    1000 = Conversion of EF
                                    <E T="52">i</E>
                                     in thousand standard cubic feet to standard cubic feet.
                                </FP>
                                <STARS/>
                            </EXTRACT>
                            <P>
                                (g) 
                                <E T="03">Well venting during completions and workovers with hydraulic fracturing.</E>
                                 Calculate annual volumetric natural gas emissions from gas well and oil well venting during completions and workovers involving hydraulic fracturing using equation W-10A or equation W-10B to this section. Equation W-10A to this section applies to well venting when the gas flowback rate is measured from a specified number of example completions or workovers and equation W-10B to this section applies when the gas flowback vent or flare volume is measured for each completion or workover. Completion and workover activities are separated into two periods, an initial period when flowback is routed to open pits or tanks and a subsequent period when gas content is sufficient to route the flowback to a separator or when the gas content is sufficient to allow measurement by the devices specified in paragraph (g)(1) of this section, regardless of whether a separator is actually utilized. If you elect to use equation W-10A to this section, you must follow the procedures specified in paragraph (g)(1) of this section. If you elect to use equation W-10B to this section, you must use a recording flow meter installed on the vent line, downstream of a separator and ahead of a flare or vent, to measure the gas flowback. To calculate emissions during the initial period, you must calculate the gas flowback rate in the initial flowback period as described in equation W-10B to this section. Alternatively, you may use a multiphase flow meter placed on the flow line downstream of the wellhead and ahead of the separator to directly measure gas flowback during the initial period when flowback is routed to open pits or tanks. If you use a multiphase flow meter, measurements must be taken from initiation of flowback to the beginning of the period of time when sufficient quantities of gas are present to enable separation. For Reporting Year 2024, you may use data collected by a multiphase flow meter anytime during the calendar year. For either equation, 
                                <PRTPAGE P="42231"/>
                                emissions must be calculated separately for completions and workovers, for each sub-basin, and for each well type combination identified in paragraph (g)(2) of this section. You must calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric and mass emissions as specified in paragraph (g)(3) of this section. If emissions from well venting during completions and workovers with hydraulic fracturing are routed to a flare, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O annual emissions as specified in paragraph (g)(4) of this section.
                            </P>
                            <GPH SPAN="3" DEEP="42">
                                <GID>ER14MY24.031</GID>
                            </GPH>
                            <GPH SPAN="3" DEEP="42">
                                <GID>ER14MY24.032</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,n</E>
                                     = Annual volumetric natural gas emissions in standard cubic feet from gas venting during well completions or workovers following hydraulic fracturing for each sub-basin and well type combination.
                                </FP>
                                <FP SOURCE="FP-2">W = Total number of wells completed or worked over using hydraulic fracturing in a sub-basin and well type combination.</FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">p,s</E>
                                     = Cumulative amount of time of flowback, after sufficient quantities of gas are present to enable separation, where gas vented or flared for the completion or workover, in hours, for each well, p, in a sub-basin and well type combination during the reporting year. This may include non-contiguous periods of venting or flaring.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">p,i</E>
                                     = Cumulative amount of time of flowback to open tanks/pits, from when gas is first detected until sufficient quantities of gas are present to enable separation, for the completion or workover, in hours, for each well, p, in a sub-basin and well type combination during the reporting year. This may include non-contiguous periods of routing to open tanks/pits but does not include periods when the oil well ceases to produce fluids to the surface.
                                </FP>
                                <FP SOURCE="FP-2">
                                    FRM
                                    <E T="52">s</E>
                                     = Ratio of average gas flowback, during the period when sufficient quantities of gas are present to enable separation, of well completions and workovers from hydraulic fracturing to 30-day production rate for the sub-basin and well type combination, calculated using procedures specified in paragraph (g)(1)(iii) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    FRM
                                    <E T="52">i</E>
                                     = Ratio of initial gas flowback rate during well completions and workovers from hydraulic fracturing to 30-day gas production rate for the sub-basin and well type combination, calculated using procedures specified in paragraph (g)(1)(iv) of this section, for the period of flow to open tanks/pits.
                                </FP>
                                <FP SOURCE="FP-2">
                                    PR
                                    <E T="52">s,p</E>
                                     = Average gas production flow rate during the first 30 days of production after completions of newly drilled wells or well workovers using hydraulic fracturing in standard cubic feet per hour of each well p, that was measured in the sub-basin and well type combination. If applicable, PR
                                    <E T="52">s,p</E>
                                     may be calculated for oil wells using procedures specified in paragraph (g)(1)(vii) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EnF
                                    <E T="52">s,p</E>
                                     = Volume of N
                                    <E T="52">2</E>
                                     injected gas in cubic feet at standard conditions that was injected into the reservoir during an energized fracture job or during flowback for each well, p, as determined by using an appropriate meter according to methods described in § 98.234(b), or by using receipts of gas purchases that are used for the energized fracture job or injection during flowback. Convert to standard conditions using paragraph (t) of this section. If the fracture process did not inject gas into the reservoir or if the injected gas is CO
                                    <E T="52">2</E>
                                     then EnF
                                    <E T="52">s,p</E>
                                     is 0.
                                </FP>
                                <FP SOURCE="FP-2">
                                    FV
                                    <E T="52">s,p</E>
                                     = Flow volume of vented or flared gas for each well, p, in standard cubic feet measured using a recording flow meter (digital or analog) on the vent line to measure gas flowback during the separation period of the completion or workover according to methods set forth in § 98.234(b).
                                </FP>
                                <FP SOURCE="FP-2">
                                    FR
                                    <E T="52">p,i</E>
                                     = Flow rate vented or flared of each well, p, in standard cubic feet per hour measured using a recording flow meter (digital or analog) on the vent line to measure the flowback, at the beginning of the period of time when sufficient quantities of gas are present to enable separation, of the completion or workover according to methods set forth in § 98.234(b). Alternatively, flow rate during the initial period may be measured using a multiphase flow meter installed upstream of the separator capable of accurately measuring gas flow prior to separation.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Z
                                    <E T="52">p,i</E>
                                     = If a multiphase flow meter is used to measure flowback during the initial period, then Z
                                    <E T="52">p,i</E>
                                     is equal to 1. If flowback is measured using a recording flow meter (digital or analog) on the vent line to measure the flowback, at the beginning of the period of time when sufficient quantities of gas are present to enable separation, then Z
                                    <E T="52">p,i</E>
                                     is equal to 0.5.
                                </FP>
                            </EXTRACT>
                            <P>(1) * * *</P>
                            <P>
                                (i) 
                                <E T="03">Calculation Method 1.</E>
                                 You must use equation W-12A to this section as specified in paragraph (g)(1)(iii) of this section to determine the value of FRM
                                <E T="52">s</E>
                                . You must use equation W-12B to this section as specified in paragraph (g)(1)(iv) of this section to determine the value of FRM
                                <E T="52">i</E>
                                . The procedures specified in paragraphs (g)(1)(v) and (vi) of this section also apply. When making gas flowback measurements for use in equations W-12A and W-12B to this section, you must use a recording flow meter (digital or analog) installed on the vent line, downstream of a separator and ahead of a flare or vent, to measure the gas flowback rates in units of standard cubic feet per hour according to methods set forth in § 98.234(b). Alternatively, you may use a multiphase flow meter placed on the flow line downstream of the wellhead and ahead of the separator to directly measure gas flowback during the initial period when flowback is routed to open pits or tanks. If you use a multiphase flow meter, measurements must be taken from initiation of flowback to the beginning of the period of time when sufficient quantities of gas are present to enable separation. For Reporting Year 2024, you may use data collected by a multiphase flow meter anytime during the calendar year.
                            </P>
                            <STARS/>
                            <P>(iv) * * *</P>
                            <EXTRACT>
                                <FP SOURCE="FP-2">
                                    FR
                                    <E T="52">i,p</E>
                                     = Initial measured gas flowback rate from Calculation Method 1 described in paragraph (g)(1)(i) of this section or initial calculated flow rate from Calculation Method 2 described in paragraph (g)(1)(ii) of this section in standard cubic feet per hour for well(s), p, for each sub-basin and well type combination. Measured and calculated FR
                                    <E T="52">i,p</E>
                                     values must be based on flow conditions at the beginning of the separation period and must be expressed at standard conditions or measured using a multiphase flow meter installed upstream of the separator capable of accurately measuring gas flow prior to separation.
                                </FP>
                            </EXTRACT>
                            <STARS/>
                            <PRTPAGE P="42232"/>
                            <P>(i) * * *</P>
                            <P>(2) * * *</P>
                            <P>(i) Calculate the total annual natural gas emissions from each unique physical volume that is blown down using either equation W-14A or W-14B to this section. For Reporting Year 2024, you may use best available information to determine temperature and pressure of any emergency blowdown during the calendar year from the industry segments specified.</P>
                            <GPH SPAN="3" DEEP="46">
                                <GID>ER14MY24.033</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,n</E>
                                     = Annual natural gas emissions at standard conditions from each unique physical volume that is blown down, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">N = Number of occurrences of blowdowns for each unique physical volume in the calendar year.</FP>
                                <FP SOURCE="FP-2">V = Unique physical volume between isolation valves, in cubic feet, as calculated in paragraph (i)(1) of this section.</FP>
                                <FP SOURCE="FP-2">C = Purge factor is 1 if the unique physical volume is not purged, or 0 if the unique physical volume is purged using non-GHG gases.</FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">s</E>
                                     = Temperature at standard conditions (60 °F).
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">a</E>
                                     = Temperature at actual conditions in the unique physical volume (°F). For emergency blowdowns at onshore petroleum and natural gas gathering and boosting facilities and onshore natural gas transmission pipeline facilities, engineering estimates based on best available information may be used to determine the temperature.
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">s</E>
                                     = Absolute pressure at standard conditions (14.7 psia).
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">a</E>
                                     = Absolute pressure at actual conditions in the unique physical volume (psia). For emergency blowdowns at onshore petroleum and natural gas gathering and boosting facilities and onshore natural gas transmission pipeline facilities, engineering estimates based on best available information may be used to determine the pressure.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Z
                                    <E T="52">a</E>
                                     = Compressibility factor at actual conditions for natural gas. You may use either a default compressibility factor of 1, or a site-specific compressibility factor based on actual temperature and pressure conditions.
                                </FP>
                            </EXTRACT>
                            <GPH SPAN="3" DEEP="48">
                                <GID>ER14MY24.034</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,n</E>
                                     = Annual natural gas emissions at standard conditions from each unique physical volume that is blown down, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">p = Individual occurrence of blowdown for the same unique physical volume.</FP>
                                <FP SOURCE="FP-2">N = Number of occurrences of blowdowns for each unique physical volume in the calendar year.</FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">p</E>
                                     = Unique physical volume between isolation valves, in cubic feet, for each blowdown “p.”
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">s</E>
                                     = Temperature at standard conditions (60 °F).
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">a,p</E>
                                     = Temperature at actual conditions in the unique physical volume (°F) for each blowdown “p”. For emergency blowdowns at onshore petroleum and natural gas gathering and boosting facilities and onshore natural gas transmission pipeline facilities, engineering estimates based on best available information may be used to determine the temperature.
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">s</E>
                                     = Absolute pressure at standard conditions (14.7 psia).
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">a,b,p</E>
                                     = Absolute pressure at actual conditions in the unique physical volume (psia) at the beginning of the blowdown “p”. For emergency blowdowns at onshore petroleum and natural gas gathering and boosting facilities and onshore natural gas transmission pipeline facilities, engineering estimates based on best available information may be used to determine the pressure at the beginning of the blowdown.
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">a,e,p</E>
                                     = Absolute pressure at actual conditions in the unique physical volume (psia) at the end of the blowdown “p”; 0 if blowdown volume is purged using non-GHG gases. For emergency blowdowns at onshore petroleum and natural gas gathering and boosting facilities and onshore natural gas transmission pipeline facilities, engineering estimates based on best available information may be used to determine the pressure at the end of the blowdown.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Z
                                    <E T="52">a</E>
                                     = Compressibility factor at actual conditions for natural gas. You may use either a default compressibility factor of 1, or a site-specific compressibility factor based on actual temperature and pressure conditions.
                                </FP>
                            </EXTRACT>
                            <P>
                                (j) 
                                <E T="03">Onshore production and onshore petroleum and natural gas gathering and boosting storage tanks.</E>
                                 Calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O (when flared) emissions from atmospheric pressure fixed roof storage tanks receiving hydrocarbon produced liquids from onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities (including stationary liquid storage not owned or operated by the reporter), as specified in this paragraph (j). For wells, gas-liquid separators, or onshore petroleum and natural gas gathering and boosting non-separator equipment (
                                <E T="03">e.g.,</E>
                                 stabilizers, slug catchers) with annual average daily throughput of oil greater than or equal to 10 barrels per day, calculate annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 using Calculation Method 1 or 2 as specified in paragraphs (j)(1) and (2) of this section. For wells, gas-liquid separators, or non-separator equipment with annual average daily throughput less than 10 barrels per day, use Calculation Method 1, 2, or 3 as specified in paragraphs (j)(1) through (3) of this section. If you use Calculation Method 1 or Calculation Method 2 for separators, you must also calculate emissions that may have occurred due to dump valves not closing properly using the method specified in paragraph (j)(6) of this section. If emissions from atmospheric pressure fixed roof storage tanks are routed to a vapor recovery system, you must adjust the emissions downward according to paragraph (j)(4) of this section. If emissions from atmospheric pressure fixed roof storage tanks are routed to a flare, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O annual emissions as specified in paragraph (j)(5) of this section. For Reporting Year 2024, you may use data collected anytime during the calendar year for any of the applicable calculation methods, provided that the data were collected in accordance with and meet 
                                <PRTPAGE P="42233"/>
                                the criteria of the applicable paragraphs (j)(1) through (3) of this section.
                            </P>
                            <STARS/>
                            <P>
                                (2) 
                                <E T="03">Calculation Method 2.</E>
                                 Calculate annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions using the methods in paragraph (j)(2)(i) of this section for gas-liquid separators. Calculate annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions using the methods in paragraph (j)(2)(ii) of this section for wells that flow directly to atmospheric storage tanks in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting (if applicable). Calculate annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions using the methods in paragraph (j)(2)(iii) of this section for non-separator equipment that flow directly to atmospheric storage tanks in onshore petroleum and natural gas gathering and boosting.
                            </P>
                            <STARS/>
                            <P>
                                (3) 
                                <E T="03">Calculation Method 3.</E>
                                 Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions using Equation W-15 of this section:
                            </P>
                            <GPH SPAN="3" DEEP="24">
                                <GID>ER14MY24.035</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,I</E>
                                     = Annual total volumetric GHG emissions (either CO
                                    <E T="52">2</E>
                                     or CH
                                    <E T="52">4</E>
                                    ) at standard conditions in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">i</E>
                                     = Population emission factor for separators, wells, or non-separator equipment in thousand standard cubic feet per separator, well, or non-separator equipment per year, for crude oil use 4.2 for CH
                                    <E T="52">4</E>
                                     and 2.8 for CO
                                    <E T="52">2</E>
                                     at 60 °F and 14.7 psia, and for gas condensate use 17.6 for CH
                                    <E T="52">4</E>
                                     and 2.8 for CO
                                    <E T="52">2</E>
                                     at 60 °F and 14.7 psia.
                                </FP>
                                <FP SOURCE="FP-2">Count = Total number of separators, wells, or non-separator equipment with annual average daily throughput less than 10 barrels per day. Count only separators, wells, or non-separator equipment that feed oil directly to the storage tank for which you elect to use this Calculation Method 3.</FP>
                                <FP SOURCE="FP-2">1,000 = Conversion from thousand standard cubic feet to standard cubic feet.</FP>
                                <STARS/>
                            </EXTRACT>
                            <P>(m) * * *</P>
                            <P>(1) If you measure the gas flow to a vent using a continuous flow measurement device, you may use measurements collected from a continuous flow measurement device anytime during the calendar year.</P>
                            <P>(2) If you do not measure the gas flow to a vent using a continuous flow measurement device or you do measure the gas flow but do not elect to use the measurements, you must follow the procedures in paragraphs (m)(2)(i) through (iii) of this section.</P>
                            <P>(i) Determine the GOR of the hydrocarbon production from each well whose associated natural gas is vented or flared. If GOR from each well is not available, use the GOR from a cluster of wells in the same sub-basin category.</P>
                            <P>(ii) If GOR cannot be determined from your available data, then you must use one of the procedures specified in paragraph (m)(2)(ii)(A) or (B) of this section to determine GOR.</P>
                            <P>(A) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists.</P>
                            <P>(B) You may use an industry standard practice as described in § 98.234(b).</P>
                            <P>(iii) Estimate venting emissions using equation W-18 to this section.</P>
                            <GPH SPAN="3" DEEP="29">
                                <GID>ER14MY24.036</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,n</E>
                                     = Annual volumetric natural gas emissions, at the facility level, from associated gas venting at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GOR
                                    <E T="52">p,q</E>
                                     = Gas to oil ratio, for well p in sub-basin q, in standard cubic feet of gas per barrel of oil; oil here refers to hydrocarbon liquids produced of all API gravities.
                                </FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">p,q</E>
                                     = Volume of oil produced, for well p in sub-basin q, in barrels in the calendar year during time periods in which associated gas was vented or flared.
                                </FP>
                                <FP SOURCE="FP-2">
                                    SG
                                    <E T="52">p,q</E>
                                     = Volume of associated gas sent to sales, for well p in sub-basin q, in standard cubic feet of gas in the calendar year during time periods in which associated gas was vented or flared.
                                </FP>
                                <FP SOURCE="FP-2">x = Total number of wells in sub-basin that vent or flare associated gas.</FP>
                                <FP SOURCE="FP-2">y = Total number of sub-basins in a basin that contain wells that vent or flare associated gas.</FP>
                            </EXTRACT>
                            <P>(3) [Reserved]</P>
                            <STARS/>
                            <P>(o) * * *</P>
                            <P>
                                (10) 
                                <E T="03">Method for calculating volumetric GHG emissions from wet seal oil degassing vents at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility.</E>
                                 You must calculate volumetric emissions from centrifugal compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility as specified in paragraphs (o)(10)(i) through (iv) of this section, as applicable. For Reporting Year 2024, you may use data collected anytime during the calendar year for any of the applicable calculation methods, provided that the data were collected in accordance with and meet the criteria of the applicable paragraphs (o)(10)(i) through (iv) of this section.
                            </P>
                            <P>(i) For all centrifugal compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility with dry seals and self-contained wet seals, you may measure compressor emissions by conducting the volumetric emission measurements as required by § 60.5380b(a)(5) of this chapter, conducting all additional volumetric emission measurements specified in paragraph (o)(1) of this section using methods specified in paragraphs (o)(2) through (5) of this section (based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement), and calculating emissions as specified in paragraphs (o)(6) through (9) of this section. Conduct all measurements required by this paragraph (o)(10)(i) at the frequency specified by § 60.5380b(a)(4) of this chapter. For any reporting year in which measuring at the frequency specified by § 60.5380b(a)(4) of this chapter results in measurement not being required for a subject compressor, calculate emissions for all mode-source combinations as specified in paragraph (o)(6)(ii) of this section.</P>
                            <P>
                                (ii) For all centrifugal compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility, you may elect to conduct the volumetric emission measurements specified in paragraph 
                                <PRTPAGE P="42234"/>
                                (o)(1) of this section using methods specified in paragraphs (o)(2) through (5) of this section (based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement), and calculate emissions as specified in paragraphs (o)(6) through (9) of this section.
                            </P>
                            <P>(iii) For all centrifugal compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility for which paragraph (o)(10)(i) of this section does not apply and you do not elect to conduct the volumetric measurements specified in paragraph (o)(1) of this section, you must calculate total atmospheric wet seal oil degassing vent emissions from all centrifugal compressors at either an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility using equation W-25A to this section.</P>
                            <GPH SPAN="3" DEEP="43">
                                <GID>ER14MY24.037</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions from all centrifugal compressors, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">Count = Total number of centrifugal compressors with wet seal oil degassing vents that are vented directly to the atmosphere.</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,p</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions for centrifugal compressor p, at standard conditions, in cubic feet, calculated using equation W-25B to this section.
                                </FP>
                            </EXTRACT>
                            <P>(iv) For all centrifugal compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility for which paragraph (o)(10)(i) of this section does not apply, and you do not elect to conduct the volumetric measurements specified in paragraph (o)(1) of this section, you must calculate wet seal oil degassing vent emissions from each centrifugal compressor using equation W-25B to this section.</P>
                            <GPH SPAN="3" DEEP="35">
                                <GID>ER14MY24.038</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,p</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions for centrifugal compressor p, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">s,p</E>
                                     = Emission factor for centrifugal compressor p, in standard cubic feet per year. Use 1.2 × 10
                                    <SU>7</SU>
                                     standard cubic feet per year per compressor for CH
                                    <E T="52">4</E>
                                     and 5.30 × 10
                                    <SU>5</SU>
                                     standard cubic feet per year per compressor for CO
                                    <E T="52">2</E>
                                     at 60 °F and 14.7 psia.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">p</E>
                                     = Total time centrifugal compressor p was in operating mode, for which E
                                    <E T="52">s,i,p</E>
                                     is being calculated in the reporting year, in hours.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">total</E>
                                     = Total hours per year. Use 8784 in leap years and use 8760 in all other years.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i,p</E>
                                     = Mole fraction of GHG (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) in the vent gas for centrifugal compressor p in operating mode; use the appropriate gas compositions in paragraph (u)(2) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">EF</E>
                                     = Mole fraction of GHG (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) used in the determination of EF
                                    <E T="52">s,p</E>
                                    . Use 0.95 for CH
                                    <E T="52">4</E>
                                     and 0.05 for CO
                                    <E T="52">2</E>
                                    .
                                </FP>
                                <STARS/>
                            </EXTRACT>
                            <P>(p) * * *</P>
                            <P>
                                (10) 
                                <E T="03">Method for calculating volumetric GHG emissions from reciprocating compressor venting at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility.</E>
                                 You must calculate volumetric emissions from reciprocating compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility as specified in paragraphs (p)(10)(i) through (iv) of this section, as applicable. For Reporting Year 2024, you may use data collected anytime during the calendar year for any of the applicable calculation methods, provided that the data were collected in accordance with and meet the criteria of the applicable paragraphs (p)(10)(i) through (iv) of this section.
                            </P>
                            <P>(i) For all reciprocating compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility, you may measure compressor emissions by conducting the volumetric emission measurements as required by § 60.5385b(b) and (c) of this chapter, conducting any additional volumetric emission measurements specified in paragraph (p)(1) of this section using methods specified in paragraphs (p)(2) through (5) of this section (based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement), and calculating emissions as specified in paragraphs (p)(6) through (9) of this section. Conduct all measurements required by this paragraph (p)(10)(i) at the frequency specified by § 60.5385b(a) of this chapter. For any reporting year in which measuring at the frequency specified by § 60.5385b(a) of this chapter results in measurement not being required for a subject compressor, calculate emissions for all mode-source combinations as specified in paragraph (p)(6)(ii) of this section.</P>
                            <P>(ii) For all reciprocating compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility, you may elect to conduct volumetric emission measurements specified in paragraph (p)(1) of this section using methods specified in paragraphs (p)(2) through (5) of this section (based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement), and calculate emissions as specified in paragraphs (p)(6) through (9) of this section.</P>
                            <P>
                                (iii) For all reciprocating compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility for which paragraph (p)(10)(i) of this section does not apply, and you do not elect to conduct volumetric emission measurements specified in paragraph (p)(1) of this section, you must calculate total atmospheric rod packing emissions from all reciprocating compressors venting at 
                                <PRTPAGE P="42235"/>
                                either an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility using equation W-29D to this section.
                            </P>
                            <GPH SPAN="3" DEEP="43">
                                <GID>ER14MY24.039</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions from all reciprocating compressors, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">Count = Total number of reciprocating compressors with rod packing emissions vented directly to the atmosphere.</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,p</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions for reciprocating compressor p, at standard conditions, in cubic feet, calculated using equation W-29E to this section.
                                </FP>
                            </EXTRACT>
                            <P>(iv) For all reciprocating compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility for which paragraph (p)(10)(i) of this section does not apply, you must calculate rod packing vent emissions from each reciprocating compressor using equation W-29E to this section. Reciprocating compressor rod packing emissions that are routed to a flare, combustion, or vapor recovery system are not required to be determined under this paragraph (p).</P>
                            <GPH SPAN="3" DEEP="34">
                                <GID>ER14MY24.040</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,p</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions for reciprocating compressor p, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">s,p</E>
                                     = Emission factor for reciprocating compressor p, in standard cubic feet per year. Use 9.48 × 10
                                    <SU>3</SU>
                                     standard cubic feet per year per compressor for CH
                                    <E T="52">4</E>
                                     and 5.27 × 10
                                    <SU>2</SU>
                                     standard cubic feet per year per compressor for CO
                                    <E T="52">2</E>
                                     at 60 °F and 14.7 psia.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">p</E>
                                     = Total time reciprocating compressor p was in operating mode, for which E
                                    <E T="52">s,i,p</E>
                                     is being calculated in the reporting year, in hours.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">total</E>
                                     = Total hours per year. Use 8784 in leap years and use 8760 in all other years.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i,p</E>
                                     = Mole fraction of GHG (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) in the vent gas for reciprocating compressor p in operating mode; use the appropriate gas compositions in paragraph (u)(2) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">EF</E>
                                     = Mole fraction of GHG (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) used in the determination of EF
                                    <E T="52">s,p</E>
                                    . Use 0.98 for CH
                                    <E T="52">4</E>
                                     and 0.02 for CO
                                    <E T="52">2</E>
                                    .
                                </FP>
                                <STARS/>
                            </EXTRACT>
                            <P>
                                (q) 
                                <E T="03">Equipment leak surveys.</E>
                                 For the components identified in paragraphs (q)(1)(i) through (iii) of this section, you must conduct equipment leak surveys using the leak detection methods specified in paragraphs (q)(1)(i) through (iii) of this section. For the components identified in paragraph (q)(1)(iv) of this section, you may elect to conduct equipment leak surveys, and if you elect to conduct surveys, you must use a leak detection method specified in paragraph (q)(1)(iv) of this section. This paragraph (q) applies to components in streams with gas content greater than 10 percent CH
                                <E T="52">4</E>
                                 plus CO
                                <E T="52">2</E>
                                 by weight. Components in streams with gas content less than or equal to 10 percent CH
                                <E T="52">4</E>
                                 plus CO
                                <E T="52">2</E>
                                 by weight are exempt from the requirements of this paragraph (q) and do not need to be reported. Tubing systems equal to or less than one half inch diameter are exempt from the requirements of this paragraph (q) and do not need to be reported. Equipment leak components in vacuum service are exempt from the survey and emission estimation requirements of this paragraph (q).
                            </P>
                            <P>
                                (1) 
                                <E T="03">Survey requirements</E>
                                —(i) For the components listed in § 98.232(e)(7), (f)(5), (g)(4), and (h)(5), that are not subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, you must conduct surveys using any of the leak detection methods listed in § 98.234(a) and calculate equipment leak emissions using the procedures specified in either paragraph (q)(2) or (3) of this section. For Reporting Year 2024, you may use data collected anytime during the calendar year for any of the applicable calculation methods, provided that the data were collected in accordance with and meet the criteria of the applicable paragraphs (q)(2) through (4) of this section.
                            </P>
                            <P>(ii) For the components listed in § 98.232(d)(7) and (i)(1), you must conduct surveys using any of the leak detection methods listed in § 98.234(a)(1) through (5) and calculate equipment leak emissions using the procedures specified in either paragraph (q)(2) or (3) of this section.</P>
                            <P>(iii) For the components listed in § 98.232(c)(21), (e)(7), (e)(8), (f)(5), (f)(6), (f)(7), (f)(8), (g)(4), (g)(6), (g)(7), (h)(5), (h)(7), (h)(8), and (j)(10) that are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, you must conduct surveys using any of the leak detection methods in § 98.234(a)(6) or (7) and calculate equipment leak emissions using the procedures specified in either paragraph (q)(2) or (3) of this section.</P>
                            <P>(iv) For the components listed in § 98.232(c)(21), (e)(8), (f)(6), (f)(7), (f)(8), (g)(6), (g)(7), (h)(7), (h)(8), or (j)(10), that are not subject to fugitive emissions standards in § 60.5397a of this chapter, you may elect to conduct surveys according to this paragraph (q), and, if you elect to do so, then you must use one of the leak detection methods in § 98.234(a).</P>
                            <P>(A) If you elect to use a leak detection method in § 98.234(a)(1) through (5) for the surveyed component types in § 98.232(c)(21), (f)(7), (g)(6), (h)(7), or (j)(10) in lieu of the population count methodology specified in paragraph (r) of this section, then you must calculate emissions for the surveyed component types in § 98.232(c)(21), (f)(7), (g)(6), (h)(7), or (j)(10) using the procedures in either paragraph (q)(2) or (3) of this section.</P>
                            <P>
                                (B) If you elect to use a leak detection method in § 98.234(a)(1) through (5) for the surveyed component types in § 98.232(e)(8), (f)(6), (f)(8), (g)(7), and (h)(8), then you must use the procedures in either paragraph (q)(2) or (3) of this section to calculate those emissions.
                                <PRTPAGE P="42236"/>
                            </P>
                            <P>(C) If you elect to use a leak detection method in § 98.234(a)(6) or (7) for any elective survey under this subparagraph (q)(1)(iv), then you must survey the component types in § 98.232(c)(21), (e)(8), (f)(6), (f)(7), (f)(8), (g)(6), (g)(7), (h)(7), (h)(8), and (j)(10) that are not subject to fugitive emissions standards in § 60.5397a of this chapter, and you must calculate emissions from the surveyed component types in § 98.232(c)(21), (e)(8), (f)(6), (f)(7), (f)(8), (g)(6), (g)(7), (h)(7), (h)(8), and (j)(10) using the emission calculation requirements in either paragraph (q)(2) or (3) of this section.</P>
                            <P>
                                (2) 
                                <E T="03">Calculation Method 1: Leaker emission factor calculation methodology.</E>
                                 If you elect not to measure leaks according to Calculation Method 2 as specified in paragraph (q)(3) of this section, you must use this Calculation Method 1 for all components included in a complete leak survey. For industry segments listed in § 98.230(a)(2) through (9), if equipment leaks are detected during surveys required or elected for components listed in paragraphs (q)(1)(i) through (iv) of this section, then you must calculate equipment leak emissions per component type per reporting facility using equation W-30 to this section and the requirements specified in paragraphs (q)(2)(i) through (xi) of this section. For the industry segment listed in § 98.230(a)(8), the results from equation W-30 to this section are used to calculate population emission factors on a meter/regulator run basis using equation W-31 to this section. If you chose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years, “n,” according to paragraph (q)(2)(x)(A) of this section, then you must calculate the emissions from all above grade transmission-distribution transfer stations as specified in paragraph (q)(2)(xi) of this section.
                            </P>
                            <STARS/>
                            <P>
                                (3) 
                                <E T="03">Calculation Method 2: Leaker measurement methodology.</E>
                                 For industry segments listed in § 98.230(a)(2) through (9), if equipment leaks are detected during surveys required or elected for components listed in paragraphs (q)(1)(i) through (iv) of this section, you may elect to measure the volumetric flow rate of each natural gas leak identified during a complete leak survey. If you elect to use this method, you must use this method for all components included in a complete leak survey and you must determine the volumetric flow rate of each natural gas leak identified during the leak survey and aggregate the emissions by the method of leak detection and component type as specified in paragraphs (q)(3)(i) through (vii) of this section. For an onshore petroleum and natural gas production facility electing to use this Calculation Method 2, a survey of all required components at a single well-pad site, as defined in § 98.238, will be considered a complete leak detection survey for purposes of this section. For an onshore petroleum and natural gas gathering and boosting facility electing to use this Calculation Method 2, a survey of all required components at a gathering and boosting site, as defined in § 98.238, will be considered a complete leak detection survey for purposes of this section.
                            </P>
                            <P>(i) Determine the volumetric flow rate of each natural gas leak identified during the leak survey following the methods § 98.234(b) through (d), as appropriate for each leak identified. You do not need to use the same measurement method for each leak measured. If you are unable to measure the natural gas leak because it would require elevating the measurement personnel more than 2 meters above the surface and a lift is unavailable at the site or it would pose immediate danger to measurement personnel, then you must substitute the default leak rate for the component and site type from tables W-1E, W-2, W-3A, W-4A, W-5A, W-6A, and W-7 to this subpart, as applicable, as the measurement for this leak.</P>
                            <P>
                                (ii) For each leak, calculate the volume of natural gas emitted as the product of the natural gas flow rate measured in paragraph (q)(3)(i) of this section and the duration of the leak. If one leak detection survey is conducted in the calendar year, assume the component was leaking for the entire calendar year. If multiple leak detection surveys are conducted in the calendar year, assume a component found leaking in the first survey was leaking since the beginning of the year until the date of the survey; assume a component found leaking in the last survey of the year was leaking from the preceding survey through the end of the year; assume a component found leaking in a survey between the first and last surveys of the year was leaking since the preceding survey until the date of the survey. For each leaking component, account for time the component was not operational (
                                <E T="03">i.e.,</E>
                                 not operating under pressure) using an engineering estimate based on best available data.
                            </P>
                            <P>(iii) For each leak, convert the volumetric emissions of natural gas determined in paragraph (q)(3)(ii) of this section to standard conditions using the method specified in paragraph (t)(1) of this section.</P>
                            <P>
                                (iv) For each leak, convert the volumetric emissions of natural gas at standard conditions determined in paragraph (q)(3)(iii) of this section to CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 volumetric emissions at standard conditions using the methods specified in paragraph (u) of this section.
                            </P>
                            <P>(v) For each leak, convert the GHG volumetric emissions at standard conditions determined in paragraph (q)(3)(iv) of this section to GHG mass emissions using the methods specified in paragraph (v) of this section.</P>
                            <P>
                                (vi) Sum the CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 mass emissions determined in paragraph (q)(3)(v) of this section separately for each type of component required to be surveyed by the method used for the survey for which a leak was detected.
                            </P>
                            <P>
                                (vii) Multiply the total CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 mass emissions by survey method and component type determined in paragraph (q)(3)(vi) by the survey specific value for “k”, the factor adjustment for undetected leaks, where k equals 1.25 for the methods in § 98.234(q)(1), (3) and (5); k equals 1.55 for the method in § 98.234(q)(2)(i); and k equals 1.27 for the method in § 98.234(q)(2)(ii).
                            </P>
                            <P>(viii) For natural gas distribution facilities:</P>
                            <P>
                                (A) Use equation W-31 to this section to determine the meter/regulator run population emission factors for each GHG
                                <E T="52">i</E>
                                 using the methods as specified in paragraphs (q)(2)(x)(A) and (B) of this section, except use the sum of the GHG volumetric emissions for each type of component required to be surveyed by the method used for the survey for which a leak was detected calculated in paragraph (q)(3)(iv) of this section rather than the emissions calculated using equation W-30 to this section.
                            </P>
                            <P>(B) If you chose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years, “n,” according to paragraph (q)(1)(viii) of this section, you must use the meter/regulator run population emission factors calculated according to paragraph (q)(3)(viii)(A) of this section and the total count of all meter/regulator runs at above grade transmission-distribution transfer stations to calculate emissions from all above grade transmission-distribution transfer stations using equation W-32B to this section.</P>
                            <P>
                                (4) 
                                <E T="03">Development of facility-specific component-level leaker emission factors by leak detection method.</E>
                                 If you elect to measure leaks according to Calculation Method 2 as specified in paragraph 
                                <PRTPAGE P="42237"/>
                                (q)(3) of this section, you must use the measurement values determined in accordance with paragraph (q)(3) of this section to calculate a facility-specific component-level leaker emission factor by leak detection method as provided in paragraphs (q)(4)(i) through (iv) of this section.
                            </P>
                            <P>(i) You must track the leak measurements made separately for each of the applicable components listed in paragraphs (q)(1)(i) through (v) of this section and by the leak detection method according to the following three bins.</P>
                            <P>(A) Method 21 as specified in § 98.234(a)(2).</P>
                            <P>(B) Method 21 as specified in § 98.234(a)(7).</P>
                            <P>(C) Optical gas imaging (OGI) and other leak detection methods as specified in § 98.234(a)(1) or (3) through (6).</P>
                            <P>(ii) You must accumulate a minimum of 50 leak measurements total for a given component type and leak detection method combination before you can develop and use a facility-specific component-level leaker emission factor for use in calculating emissions according to paragraph (q)(2) of this section (Calculation Method 1: Leaker emission factor calculation methodology).</P>
                            <P>(iii) Sum the volumetric flow rate of natural gas determined in accordance with paragraph (q)(3)(i) of this section for each leak by component type and leak detection method as specified in paragraph (q)(4)(i) of this section meeting the minimum number of measurement requirement in paragraph (q)(4)(ii) of this section.</P>
                            <P>(iv) Convert the volumetric flow rate of natural gas determined in paragraph (q)(4)(iii) of this section to standard conditions using the method specified in paragraph (t)(1) of this section.</P>
                            <P>(v) Determine the emission factor in units of standard cubic feet per hour component (scf/hr-component) by dividing the sum of the volumetric flow rate of natural gas determined in paragraph (q)(4)(iv) of this section by the total number of leak measurements for that component type and leak detection method combination.</P>
                            <P>(vi) You must update the emission factor determined in (q)(4)(v) of this section annually to include the results from all complete leak surveys for which leak measurement was performed during the reporting year in accordance with paragraph (q)(3) of this section.</P>
                            <STARS/>
                            <P>(s) * * *</P>
                            <P>(1) Offshore production facilities under BOEMRE jurisdiction shall calculate emissions as specified in paragraph (s)(1)(i) or (ii) of this section, as applicable.</P>
                            <P>(i) Report the same annual emissions as calculated and reported by BOEMRE in data collection and emissions estimation study published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS).</P>
                            <P>(ii) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication year, calculate emissions as specified in paragraph (s)(1)(i) of this section or adjust the most recent BOEMRE reported emissions data published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS) based on the operating time for the facility relative to the operating time in the most recent BOEMRE published study.</P>
                            <P>(2) Offshore production facilities that are not under BOEMRE jurisdiction must calculate emissions as specified in paragraph (s)(2)(i) or (ii) of this section, as applicable.</P>
                            <P>(i) Use the most recent monitoring methods and calculation methods published by BOEMRE referenced in 30 CFR 250.302 through 250.304 to calculate and report annual emissions (GOADS).</P>
                            <P>(ii) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication, you may calculate emissions as specified in paragraph (s)(2)(i) of this section or report the most recently reported emissions data submitted to demonstrate compliance with this subpart of part 98, with emissions adjusted based on the operating time for the facility relative to operating time in the previous reporting period.</P>
                            <STARS/>
                            <P>(z) * * *</P>
                            <P>(1) If a fuel combusted in the stationary or portable equipment is listed in table C-1 to subpart C of this part, or is a blend containing one or more fuels listed in table C-1, calculate emissions according to paragraph (z)(1)(i) of this section. If the fuel combusted is natural gas and is of pipeline quality specification and has a minimum high heat value of 950 Btu per standard cubic foot, use the calculation method described in paragraph (z)(1)(i) of this section and you may use the emission factor provided for natural gas as listed in table C-1. If the fuel combusted is natural gas, has a minimum higher heating value of 950 Btu per standard cubic foot, has a maximum higher heating value of 1,100 Btu per standard cubic foot, and has a minimum methane content of at least 70 percent, use the calculation method described in paragraph (z)(1)(iii) of this section. If the fuel is natural gas and does not meet the specifications of this paragraph (z)(1), calculate emissions according to paragraph (z)(2) of this section. If the fuel is field gas, process vent gas, or a blend containing field gas or process vent gas, calculate emissions according to paragraph (z)(2) of this section.</P>
                            <STARS/>
                            <P>
                                (iii) For natural gas with a minimum higher heating value of 950 Btu per standard cubic foot, a maximum higher heating value of 1,100 Btu per standard cubic foot, and a minimum methane content of at least 70 percent, calculate CO
                                <E T="52">2</E>
                                , CH
                                <E T="52">4</E>
                                , and N
                                <E T="52">2</E>
                                O emissions for each unit or group of units combusting the same fuel according to Tier 2, Tier 3, or Tier 4 listed in subpart C of this part. You must follow all applicable calculation requirements for that tier listed in § 98.33, any monitoring or QA/QC requirements listed for that tier in § 98.34, any missing data procedures specified in § 98.35, and any recordkeeping requirements specified in § 98.37.
                            </P>
                            <P>(2) For fuel combustion units that combust field gas, process vent gas, a blend containing field gas or process vent gas, or natural gas that does not met the criteria of paragraph (z)(1) of this section, calculate combustion emissions as follows:</P>
                            <STARS/>
                            <P>(ii) If you have a continuous gas composition analyzer on fuel to the combustion unit, you must use these compositions for determining the concentration of gas hydrocarbon constituent in the flow of gas to the unit. If you do not have a continuous gas composition analyzer on gas to the combustion unit, you may use engineering estimates based on best available data to determine the concentration of each constituent in the flow of gas to the unit or group of units. Otherwise, you must use the appropriate gas compositions for each stream of hydrocarbons going to the combustion unit as specified in the applicable paragraph in (u)(2) of this section.</P>
                            <STARS/>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>13. Revise and republish § 98.233 to read as follows</AMDPAR>
                        <SECTION>
                            <SECTNO>§ 98.233</SECTNO>
                            <SUBJECT>Calculating GHG emissions.</SUBJECT>
                            <P>
                                You must calculate and report the annual GHG emissions as prescribed in this section. For calculations that specify measurements in actual conditions, reporters may use a flow or volume measurement system that corrects to standard conditions and 
                                <PRTPAGE P="42238"/>
                                determine the flow or volume at standard conditions; otherwise, reporters must use average atmospheric conditions or typical operating conditions as applicable to the respective monitoring methods in this section.
                            </P>
                            <P>
                                (a) 
                                <E T="03">Natural gas pneumatic device venting.</E>
                                 Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from natural gas pneumatic device venting using the applicable provisions as specified in this paragraph (a) of this section. If you have a continuous flow meter on the natural gas supply line dedicated to any one or combination of natural gas pneumatic devices or natural gas driven pneumatic pumps vented directly to the atmosphere for any portion of the year, you must use the method specified in paragraph (a)(1) of this section to calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from those devices. For natural gas pneumatic devices vented directly to the atmosphere for which the natural gas supply rate is not continuously measured, use the applicable methods specified in paragraphs (a)(2) through (7) of this section to calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions. For natural gas pneumatic devices that are routed to flares, combustion, or vapor recovery systems, use the applicable provisions specified in paragraphs (a)(8) of this section. All references to natural gas pneumatic devices for Calculation Method 1 in this paragraph (a) also apply to combinations of natural gas pneumatic devices and natural gas driven pneumatic pumps that are served by a common natural gas supply line.
                            </P>
                            <P>
                                (1) 
                                <E T="03">Calculation Method 1.</E>
                                 If you have or elect to install a continuous flow meter that is capable of meeting the requirements of § 98.234(b) on the natural gas supply line dedicated to any one or combination of natural gas pneumatic devices and natural gas driven pneumatic pumps that are vented directly to the atmosphere, you must use the applicable methods specified in paragraph (a)(1)(i) through (iv) of this section to calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from those devices.
                            </P>
                            <P>(i) For volumetric flow monitors:</P>
                            <P>
                                (A) Determine the cumulative annual volumetric flow, in standard cubic feet, as measured by the flow monitor in the reporting year. If all natural gas pneumatic devices supplied by the measured natural gas supply line are routed to the atmosphere for only a portion of the year and are routed to a flare, combustion, or vapor recovery system for the remaining portion of the year, determine the cumulative annual volumetric flow considering only those times when one or more of the natural gas pneumatic devices were vented directly to the atmosphere. If the flow meter was installed during the year, calculate the total volumetric flow for the year based on the measured volumetric flow times the total hours in the calendar year the devices were in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) divided by the number of hours the devices were in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) and the volumetric flow was being measured.
                            </P>
                            <P>
                                (B) Convert the natural gas volumetric flow from paragraph (a)(1)(i)(A) of this section to CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions following the provisions in paragraph (u) of this section.
                            </P>
                            <P>
                                (C) Convert the CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions from paragraph (a)(1)(i)(B) of this section to CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions using calculations in paragraph (v) of this section.
                            </P>
                            <P>(ii) For mass flow monitors:</P>
                            <P>
                                (A) Determine the cumulative annual mass flow, in metric tons, as measured by the flow monitor in the reporting year. If all natural gas pneumatic devices supplied by the measured natural gas supply line are vented directly to the atmosphere for only a portion of the year and are routed to a flare, combustion, or vapor recovery system for the remaining portion of the year, determine the cumulative annual mass flow considering only those times when one or more of the natural gas pneumatic devices were vented directly to the atmosphere. If the flow meter was installed during the year, calculate the total mass flow for the year based on the measured mass flow times the total hours in the calendar year the devices were in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) divided by the number of hours the devices were in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) and the mass flow was being measured.
                            </P>
                            <P>
                                (B) Convert the cumulative mass flow from paragraph (a)(1)(ii)(A) of this section to CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions by multiplying by the mass fraction of CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 in the supplied natural gas. You must follow the provisions in paragraph (u) of this section for determining the mole fraction of CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 and use molecular weights of 16 kg/kg-mol and 44 kg/kg-mol for CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                , respectively. You may assume unspecified components have an average molecular weight of 28 kg/kg-mol.
                            </P>
                            <P>(iii) If the flow meter on the natural gas supply line serves both natural gas pneumatic devices and natural gas driven pneumatic pumps, disaggregate the total measured amount of natural gas to pneumatic devices and natural gas driven pneumatic pumps based on engineering calculations and best available data.</P>
                            <P>(iv) The flow meter must be operated and calibrated according to the methods set forth in § 98.234(b).</P>
                            <P>
                                (2) 
                                <E T="03">Calculation Method 2.</E>
                                 Except as provided in paragraph (a)(1) of this section, you may elect to measure the volumetric flow rate of each natural gas pneumatic device vent that vents directly to the atmosphere at your well-pad site, gathering and boosting site, or facility as specified in paragraphs (a)(2)(i) through (ix) of this section. You must exclude the counts of devices measured according to paragraph (a)(1) of this section from the counts of devices to be measured or for which emissions are calculated according to the requirements in this paragraph (a)(2).
                            </P>
                            <P>(i) For facilities in the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments, you may elect to measure your pneumatic devices according to this Calculation Method 2 for some well-pad sites or gathering and boosting sites and use other methods for other sites. When you elect to measure the emissions from natural gas pneumatic devices according to this Calculation Method 2 at a well-pad site or gathering and boosting site, you must measure all natural gas pneumatic devices that are vented directly to the atmosphere at the well-pad site or gathering and boosting site during the same calendar year and you must measure and calculate emissions according to the provisions in paragraphs (a)(2)(iii) through (viii) of this section.</P>
                            <P>(ii) For facilities in the onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, or natural gas distribution industry segments electing to use this Calculation Method 2, you must measure all natural gas pneumatic devices vented directly to the atmosphere at your facility each year or, if your facility has 26 or more pneumatic devices, over multiple years, not to exceed the number of years as specified in paragraphs (a)(2)(ii)(A) through (D) of this section. If you elect to measure your pneumatic devices over multiple years, you must measure approximately the same number of devices each year. You must measure and calculate emissions for natural gas pneumatic devices at your facility according to the provisions in paragraphs (a)(2)(iii) through (ix), as applicable.</P>
                            <P>
                                (A) If your facility has at least 26 but not more than 50 natural gas pneumatic devices vented directly to the atmosphere, the maximum number of 
                                <PRTPAGE P="42239"/>
                                years to measure all devices at your facility is 2 years.
                            </P>
                            <P>(B) If your facility has at least 51 but not more than 75 natural gas pneumatic devices vented directly to the atmosphere, the maximum number of years to measure all devices at your facility is 3 years.</P>
                            <P>(C) If your facility has at least 76 but not more than 100 natural gas pneumatic devices vented directly to the atmosphere, the maximum number of years to measure all devices at your facility is 4 years.</P>
                            <P>(D) If your facility has 101 or more natural gas pneumatic devices vented directly to the atmosphere, the maximum number of years to measure all devices at your facility is 5 years.</P>
                            <P>(iii) For all industry segments, determine the volumetric flow rate of each natural gas pneumatic device vent (in standard cubic feet per hour) using one of the methods specified in § 98.234(b) through (d), as appropriate, according to the requirements specified in paragraphs (a)(2)(iii)(A) through (E) of this section. You must measure the emissions under representative conditions representative of normal operations, which excludes periods immediately after conducting maintenance on the device or manually actuating the device.</P>
                            <P>
                                (A) If you use a temporary meter, such as a vane anemometer, according to the methods set forth in § 98.234(b) or a high volume sampler according to methods set forth in § 98.234(d), you must measure the emissions from each device for a minimum of 15 minutes while the device is in service (i.e., supplied with natural gas), except for natural gas pneumatic isolation valve actuators. For natural gas pneumatic isolation valve actuators, you must measure the emissions from each device for a minimum of 5 minutes while the device is in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas). If there is no measurable flow from the natural gas pneumatic device after the minimum sampling period, you can discontinue monitoring and follow the applicable methods in paragraph (a)(2)(v) of this section.
                            </P>
                            <P>(B) If you use calibrated bagging, follow the methods set forth in § 98.234(c) except you need only fill one bag to have a valid measurement. You must collect sample for a minimum of 5 minutes for natural gas pneumatic isolation valve actuators or 15 minutes for other natural gas pneumatic devices. If no gas is collected in the calibrated bag during the minimum sampling period, you can discontinue monitoring and follow the applicable methods in paragraph (a)(2)(v) of this section. If gas is collected in the bag during the minimum sampling period, you must either continue sampling until you fill the calibrated bag or you may elect to remeasure the vent according to paragraph (a)(2)(iii)(A) of this section.</P>
                            <P>(C) You do not need to use the same measurement method for each natural gas pneumatic device vent.</P>
                            <P>(D) If the measurement method selected measures the volumetric flow rate in actual cubic feet, convert the measured flow to standard cubic feet following the methods specified in paragraph (t)(1) of this section.</P>
                            <P>(E) If there is measurable flow from the device vent, calculate the volumetric flow rate of each natural gas pneumatic device vent (in standard cubic feet per hour) by dividing the cumulative volume of natural gas measured during the measurement period (in standard cubic feet) by the duration of the measurement (in hours).</P>
                            <P>
                                (iv) For all industry segments, if there is measurable flow from the device vent, calculate the volume of natural gas emitted from each natural gas pneumatic device vent as the product of the natural gas flow rate measured in paragraph (a)(2)(iii) of this section and the number of hours the pneumatic device was in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) in the calendar year.
                            </P>
                            <P>(v) For all industry segments, if there is no measurable flow from the device vent, estimate the emissions from the device according to the methods in paragraphs (a)(2)(v)(A) through (C) of this section, as applicable.</P>
                            <P>(A) For continuous high bleed pneumatic devices:</P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) Confirm that the device is in-service. If not, remeasure the device according to paragraph (a)(2)(iii) of this section at a time the device is in-service and calculate natural gas emissions from the device according to paragraph (a)(2)(iv) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) Confirm that the device is correctly characterized as a continuous high bleed pneumatic device according to the provisions in paragraph (a)(6) of this section. If the device type was mischaracterized, recharacterize the device type and use the appropriate methods in paragraph (a)(2)(v)(B) or (C) of this section, as applicable.
                            </P>
                            <P>
                                (
                                <E T="03">3</E>
                                ) Upon confirmation of the items in paragraphs (a)(2)(v)(A)(
                                <E T="03">1</E>
                                ) and (
                                <E T="03">2</E>
                                ) of this section, remeasure the device vent using a different measurement method specified in § 98.234(b) through (d) or longer monitoring duration until there is a measurable flow from the device and calculate the natural gas emissions from the device according to paragraph (a)(2)(iv) of this section.
                            </P>
                            <P>(B) For continuous low bleed pneumatic devices:</P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) Confirm that the device is in-service. If not, remeasure the device according to paragraph (a)(2)(iii) of this section at a time the device is in-service and calculate natural gas emissions from the device according to paragraph (a)(2)(iv) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) Determine natural gas bleed rate (in standard cubic feet per hour) at the supply pressure used for the pneumatic device based on the manufacturer's steady state natural gas bleed rate reported for the device. If the steady state bleed rate is reported in terms of air consumption, multiply the air consumption rate by 1.29 to calculate the steady state natural gas bleed rate. If a steady state bleed rate is not reported, follow the requirements in paragraph (a)(2)(v)(B)(
                                <E T="03">4</E>
                                ) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">3</E>
                                ) Calculate the volume of natural gas emitted from the natural gas pneumatic device vent as the product of the natural gas steady state bleed rate determined in paragraph (a)(2)(v)(B)(
                                <E T="03">2</E>
                                ) of this section and number of hours the pneumatic device was in service (
                                <E T="03">i.e.</E>
                                , supplied with natural gas) in the calendar year.
                            </P>
                            <P>
                                (
                                <E T="03">4</E>
                                ) If a steady state bleed rate is not reported, reassess whether the device is correctly characterized as a continuous low bleed pneumatic device according to the provisions in paragraph (a)(7) of this section. If the device is confirmed to be a continuous low bleed pneumatic device, you must remeasure the device vent using a different measurement method specified in § 98.234(b) through (d) or longer monitoring duration until there is a measurable flow from the device and calculate natural gas emissions from the device according to paragraph (a)(2)(iv) of this section. If the device type was mischaracterized, recharacterize the device type and use the appropriate methods in paragraph (a)(2)(v)(A) or (C) of this section, as applicable.
                            </P>
                            <P>(C) For intermittent bleed pneumatic devices:</P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) Confirm that the device is in-service. If not, remeasure the device according to paragraph (a)(2)(iii) of this section at a time the device is in-service and calculate natural gas emissions according to paragraph (a)(2)(iv) of this section. For devices confirmed to be in-service during the measurement period, calculate natural gas emissions according to paragraphs (a)(2)(v)(C)(
                                <E T="03">2</E>
                                ) through (
                                <E T="03">5</E>
                                ) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) Calculate the volume of the controller, tubing and actuator (in actual cubic feet) based on the device and tubing size.
                            </P>
                            <P>
                                (
                                <E T="03">3</E>
                                ) Sum the volumes in paragraph (a)(2)(v)(C)(
                                <E T="03">2</E>
                                ) of this section and convert the volume to standard cubic feet following the methods specified in 
                                <PRTPAGE P="42240"/>
                                paragraph (t)(1) of this section based on the natural gas supply pressure.
                            </P>
                            <P>
                                (
                                <E T="03">4</E>
                                ) Estimate the number of actuations during the year based on company records, if available, or best engineering estimates. For isolation valve actuators, you may multiply the number of valve closures during the year by 2 (one actuation to close the valve; one actuation to open the valve).
                            </P>
                            <P>
                                (
                                <E T="03">5</E>
                                ) Calculate the volume of natural gas emitted from the natural gas pneumatic device vent as the product of the per actuation volume in standard cubic feet determined in paragraph (a)(2)(v)(C)(3) of this section, the number of actuations during the year as determined in paragraph (a)(2)(v)(C)(
                                <E T="03">4</E>
                                ) of this section, and the relay correction factor. Use 1 for the relay correction factor if there is no relay; use 3 for the relay correction factor if there is a relay.
                            </P>
                            <P>
                                (vi) For each pneumatic device, convert the volumetric emissions of natural gas at standard conditions determined in paragraph (a)(2)(iv) or (v) of this section, as applicable, to CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 volumetric emissions at standard conditions using the methods specified in paragraph (u) of this section.
                            </P>
                            <P>(vii) For each pneumatic device, convert the GHG volumetric emissions at standard conditions determined in paragraph (a)(2)(vi) of this section to GHG mass emissions using the methods specified in paragraph (v) of this section.</P>
                            <P>
                                (viii) Sum the CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 mass emissions determined in paragraph (a)(2)(vii) of this section separately for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed).
                            </P>
                            <P>(ix) For facilities in the onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, or natural gas distribution industry segments, if you chose to conduct natural gas pneumatic device measurements over multiple years, “n,” according to paragraph (a)(2)(ii) of this section, then you must calculate the emissions from all pneumatic devices at your facility as specified in paragraph (a)(2)(ix)(A) through (E) of this section.</P>
                            <P>(A) Use the emissions calculated in (a)(2)(viii) of this section for the devices measured during the reporting year.</P>
                            <P>
                                (B) Calculate the whole gas emission factor for each type of pneumatic device at the facility using equation W-1A to this section and all available data from the current year and the previous years in your monitoring cycle (n-1 years) for which natural gas pneumatic device vent measurements were made according to Calculation Method 2 in paragraph (a)(2) of this section (
                                <E T="03">e.g.,</E>
                                 if your monitoring cycle is 3 years, then use measured data from the current year and the two previous years). This emission factor must be updated annually.
                            </P>
                            <GPH SPAN="3" DEEP="37">
                                <GID>ER14MY24.041</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">t</E>
                                     = Whole gas population emission factor for natural gas pneumatic device vents of type “t” (continuous high bleed, continuous low bleed, intermittent bleed), in standard cubic feet per hour per device.
                                </FP>
                                <FP SOURCE="FP-2">
                                    MT
                                    <E T="52">s,t,y</E>
                                     = Volumetric whole gas emissions rate measurement at standard (“s”) conditions from component type “t” during year “y” in standard cubic feet per hour, as calculated in paragraph (a)(2)(iii) [if there was measurable flow from the device vent], (a)(2)(v)(B)(
                                    <E T="03">2</E>
                                    ), or (a)(2)(v)(C)(
                                    <E T="03">6</E>
                                    ) of this section, as applicable.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Count
                                    <E T="52">t,y</E>
                                     = Count of natural gas pneumatic device vents of type “t” measured according to Calculation Method 2 in year “y.”
                                </FP>
                                <FP SOURCE="FP-2">n = Number of years of data to include in the emission factor calculation according to the number of years used to monitor all natural gas pneumatic device vents at the facility.</FP>
                            </EXTRACT>
                            <P>
                                (C) Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions from continuous high bleed, continuous low bleed, and intermittent bleed natural gas pneumatic devices that were not measured during the reporting year using equation W-1B to this section.
                            </P>
                            <GPH SPAN="3" DEEP="32">
                                <GID>ER14MY24.042</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i</E>
                                     = Annual total volumetric GHG emissions at standard conditions in standard cubic feet per year from natural gas pneumatic device vents, of types “t” (continuous high bleed, continuous low bleed, intermittent bleed), for GHG
                                    <E T="52">i</E>
                                    .
                                </FP>
                                <FP SOURCE="FP-2">
                                    Count
                                    <E T="52">t</E>
                                     = Total number of natural gas pneumatic devices of type “t” (continuous high bleed, continuous low bleed, intermittent bleed) as determined in paragraphs (a)(5) through (7) of this section that vent directly to the atmosphere and that were not directly measured according to the requirements in paragraph (a)(1) or (a)(2)(iii) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">t</E>
                                     = Population emission factors for natural gas pneumatic device vents (in standard cubic feet per hour per device) of each type “t” (continuous high bleed, continuous low bleed, intermittent bleed) as calculated using equation W-1A to this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i</E>
                                     = Concentration of GHG
                                    <E T="52">i</E>
                                     CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    , in produced natural gas or processed natural gas for each facility as specified in paragraph (u)(2) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">t</E>
                                     = Average estimated number of hours in the operating year the devices, of each type “t”, were in service (
                                    <E T="03">i.e.,</E>
                                     supplied with natural gas) using engineering estimates based on best available data. Default is 8,760 hours.
                                </FP>
                            </EXTRACT>
                            <P>
                                (D) Convert the volumetric emissions calculated using equation W-1B to this section to CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions using the methods specified in paragraph (v) of this section.
                            </P>
                            <P>
                                (E) Sum the CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions calculated in paragraphs (a)(2)(ix)(A) and (D) of this section separately for each type of pneumatic device (continuous high bleed, continuous low bleed, intermittent bleed) to calculate the total CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions by device type for Calculation Method 2.
                            </P>
                            <P>
                                (3) 
                                <E T="03">Calculation Method 3.</E>
                                 For facilities in the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments, you may elect to use the applicable methods specified in paragraphs (a)(3)(i) through (iv) of this section, as applicable, to calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from your natural gas pneumatic devices that are vented directly to the atmosphere at your site except those that are measured 
                                <PRTPAGE P="42241"/>
                                according to paragraph (a)(1) or (2) of this section. You must exclude the counts of devices measured according to paragraph (a)(1) of this section from the counts of devices to be monitored or for which emissions are calculated according to the requirements in this paragraph (a)(3). You may not use this Calculation Method 3 for those well-pad sites or gathering and boosting sites for which you elected to measure emissions according to paragraph (a)(2) of this section.
                            </P>
                            <P>
                                (i) For continuous high bleed and continuous low bleed natural gas pneumatic devices vented directly to the atmosphere, you must calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions using either the methods in paragraph (a)(3)(i)(A) or (B) of this section.
                            </P>
                            <P>(A) Measure all continuous high bleed and continuous low bleed pneumatic devices at your well-pad site or gathering and boosting site, as applicable, according to the provisions in paragraphs (a)(2) of this section.</P>
                            <P>(B) Use equation W-1B to this section, except use the appropriate default whole gas population emission factors for natural gas pneumatic device vents (in standard cubic feet per hour per device) of each type “t” (continuous high bleed and continuous low bleed) as listed in table W-1 to this subpart.</P>
                            <P>(ii) For intermittent bleed pneumatic devices, you must monitor each intermittent bleed pneumatic device at your well-pad site or gathering and boosting site as specified in paragraphs (a)(3)(ii)(A) through (C) of this section, as applicable.</P>
                            <P>(A) You must use one of the monitoring methods specified in § 98.234(a)(1) through (3) except that the monitoring dwell time for each device vent must be at least 2 minutes or until a malfunction is identified, whichever is shorter. A device is considered malfunctioning if any leak is observed when the device is not actuating or if a leak is observed for more than 5 seconds, or the extended duration as specified in paragraph (a)(3)(ii)(C) of this section if applicable, during a device actuation. If you cannot tell when a device is actuating, any observed leak from the device indicates a malfunctioning device.</P>
                            <P>(B) If you elect to monitor emissions from natural gas pneumatic devices at a well-pad site or gathering and boosting site according to this Calculation Method 3, you must monitor all natural gas intermittent bleed pneumatic devices that are vented directly to the atmosphere at the well-pad site or gathering and boosting site during the same calendar year. You must monitor the natural gas intermittent bleed pneumatic devices under conditions representative of normal operations, which excludes periods immediately after conducting maintenance on the device or manually actuating the device.</P>
                            <P>
                                (C) For certain throttling pneumatic devices or isolation valve actuators on pipes greater than 5 inches in diameter, that may actuate for more than 5 seconds under normal conditions, you may elect to identify individual devices for which longer bleed periods may be allowed as specified in paragraphs (a)(3)(ii)(C)(
                                <E T="03">1</E>
                                ) and (
                                <E T="03">2</E>
                                ) of this section prior to monitoring these devices for the first time.
                            </P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) You must identify the devices for which extended actuations are considered normal operations. For each device identified, you must determine the typical actuation time and maintain documentation and rationale for the extended actuation duration value.
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) You must clearly and permanently tag the device vent for each natural gas pneumatic device that has an extended actuation duration. The tag must include the device ID and the normal duration period (in seconds) as determined and documented for the device as specified in paragraph (a)(3)(ii)(C)(1) of this section.
                            </P>
                            <P>
                                (iii) For intermittent bleed pneumatic devices that are monitored according to paragraph (a)(3)(ii) of this section during the reporting year, you must calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions from intermittent bleed natural gas pneumatic devices vented directly to the atmosphere using equation W-1C to this section.
                            </P>
                            <GPH SPAN="3" DEEP="37">
                                <GID>ER14MY24.043</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">i</E>
                                     = Annual total volumetric emissions of GHGi from intermittent bleed natural gas pneumatic devices in standard cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i</E>
                                     = Concentration of GHGi, CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    , in natural gas supplied to the intermittent bleed natural gas pneumatic device as defined in paragraph (u)(2) of this section.
                                </FP>
                                <FP SOURCE="FP-2">x = Total number of intermittent bleed natural gas pneumatic devices detected as malfunctioning in any pneumatic device monitoring survey during the year. A component found as malfunctioning in two or more surveys during the year is counted as one malfunctioning component.</FP>
                                <FP SOURCE="FP-2">
                                    K
                                    <E T="52">1</E>
                                     = Whole gas emission factor for malfunctioning intermittent bleed natural gas pneumatic devices, in standard cubic feet per hour per device. Use 24.1 for well-pad sites in the onshore petroleum and natural gas production industry segment and use 16.1 for gathering and boosting sites in the onshore petroleum and natural gas gathering and boosting industry segment.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">mal,z</E>
                                     = The total time the surveyed pneumatic device “z” was in service (
                                    <E T="03">i.e.,</E>
                                     supplied with natural gas) and assumed to be malfunctioning, in hours. If one pneumatic device monitoring survey is conducted in the calendar year, assume the device found malfunctioning was malfunctioning for the entire calendar year. If multiple pneumatic device monitoring surveys are conducted in the calendar year, assume a device found malfunctioning in the first survey was malfunctioning since the beginning of the year until the date of the survey; assume a device found malfunctioning in the last survey of the year was malfunctioning from the preceding survey through the end of the year; assume a device found malfunctioning in a survey between the first and last surveys of the year was malfunctioning since the preceding survey until the date of the survey; and sum times for all malfunctioning periods.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">t,z</E>
                                     = The total time the surveyed natural gas pneumatic device “z” was in service (
                                    <E T="03">i.e.,</E>
                                     supplied with natural gas) during the year. Default is 8,760 hours for non-leap years and 8,784 hours for leap years.
                                </FP>
                                <FP SOURCE="FP-2">
                                    K
                                    <E T="52">2</E>
                                     = Whole gas emission factor for properly operating intermittent bleed natural gas pneumatic devices, in standard cubic feet per hour per device. Use 0.3 for well-pad sites in the onshore petroleum and natural gas production industry segment and use 2.8 for gathering and boosting sites in the onshore petroleum and natural gas gathering and boosting industry segment.
                                </FP>
                                <FP SOURCE="FP-2">Count = Total number of intermittent bleed natural gas pneumatic devices that were never observed to be malfunctioning during any monitoring survey during the year.</FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">avg</E>
                                     = The average time the intermittent bleed natural gas pneumatic devices that were never observed to be malfunctioning during any monitoring survey were in service (
                                    <E T="03">i.e.,</E>
                                     supplied with natural gas) using engineering estimates based on best available data. 
                                    <PRTPAGE P="42242"/>
                                    Default is 8,760 hours for non-leap years and 8,784 hours for leap years.
                                </FP>
                            </EXTRACT>
                            <P>(A) You must conduct at least one complete pneumatic device monitoring survey in a calendar year. If you conduct multiple complete pneumatic device monitoring surveys in a calendar year, you must use the results from each complete pneumatic device monitoring survey when calculating emissions using equation W-1C to this section.</P>
                            <P>(B) For the purposes of paragraph (a)(3)(iii)(A) of this section, a complete monitoring survey is a survey of all intermittent bleed natural gas pneumatic devices vented directly to the atmosphere at a well-pad site for onshore petroleum and natural gas production facilities (except those measured according to paragraph (a)(1) of this section) or all intermittent bleed pneumatic devices vented directly to the atmosphere at a gathering and boosting site for onshore petroleum and natural gas gathering and boosting facilities (except those measured according to paragraph (a)(1) of this section).</P>
                            <P>
                                (iv) You must convert the CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions as determined according to paragraphs (a)(3)(i) and (iii) of this section and calculate both CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 mass emissions using calculations in paragraph (v) of this section for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed).
                            </P>
                            <P>
                                (4) 
                                <E T="03">Calculation Method 4.</E>
                                 For well-pads in the onshore petroleum and natural gas production industry segment, gathering and boosting sites in the onshore petroleum and natural gas gathering and boosting industry segments, or for facilities in the onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, or natural gas distribution industry segments, you may elect to calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from your natural gas pneumatic devices that are vented directly to the atmosphere at your site using the methods specified in paragraphs (a)(4)(i) and (ii) of this section except those that are measured according to paragraphs (a)(1) through (3) of this section. You must exclude the counts of devices measured according to paragraph (a)(1) of this section from the counts of devices to be monitored or for which emissions are calculated according to the requirements in this paragraph (a)(4). You may not use this Calculation Method 4 for those devices for which you elected to measure emissions according to paragraph (a)(1), (2), or (3) of this section.
                            </P>
                            <P>
                                (i) You must calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions using equation W-1B to this section, except use the appropriate default whole gas population emission factors for natural gas pneumatic device vents (in standard cubic feet per hour per device) of each type “t” (continuous high bleed, continuous low bleed, and intermittent bleed) as listed in table W-1 to this subpart.
                            </P>
                            <P>
                                (ii) You must convert the CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions as determined according to paragraphs (a)(4)(i) of this section and calculate both CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 mass emissions using calculations in paragraph (v) of this section for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed).
                            </P>
                            <P>
                                (5) 
                                <E T="03">Counts of natural gas pneumatic devices.</E>
                                 For all industry segments, determine “Countt” for equation W-1A, W-1B, or W-1C to this section for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed) by counting the total number of devices at the well-pad site, gathering and boosting site, or facility, as applicable, the number of devices that are vented directly to the atmosphere and the number of those devices that were measured or monitored during the reporting year, as applicable, except as specified in paragraph (a)(6) of this section.
                            </P>
                            <P>
                                (6) 
                                <E T="03">Counts of onshore petroleum and natural gas production industry segment or the onshore petroleum and natural gas gathering and boosting natural gas pneumatic devices.</E>
                                 For facilities in the onshore petroleum and natural gas production industry segment or the onshore petroleum and natural gas gathering and boosting industry segment, you have the option in the first two consecutive calendar years to determine the total number of natural gas pneumatic devices at the facility and the number of devices that are vented directly to the atmosphere for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed), as applicable, using engineering estimates based on best available data. Counts of natural gas pneumatic devices measured or monitored during the reporting year must be made based on actual counts.
                            </P>
                            <P>
                                (7) 
                                <E T="03">Type of natural gas pneumatic devices.</E>
                                 For all industry segments, determine the type of natural gas pneumatic device using engineering estimates based on best available information.
                            </P>
                            <P>
                                (8) 
                                <E T="03">Routing to flares, combustion, or vapor recovery systems.</E>
                                 Calculate emissions from natural gas pneumatic devices routed to flares, combustion, or vapor recovery systems as specified in paragraph (a)(8)(i) or (ii) of this section, as applicable. If a device was vented directly to the atmosphere for part of the year and routed to a flare, combustion unit, or vapor recovery system during another part of the year, then calculate emissions from the time the device vents directly to the atmosphere as specified in paragraph (a)(1), (2), (3) or (4) of this section, as applicable, and calculate emissions from the time the device was routed to a flare or combustion as specified in paragraph (a)(8)(i) or (ii) of this section, as applicable. During periods when natural gas pneumatic device emissions are collected in a vapor recovery system that is not routed to combustion, paragraphs (a)(1) through (4) and (a)(8)(i) and (ii) of this section do not apply and no emissions calculations are required. Notwithstanding the calculation and emissions reporting requirements as specified in this paragraph (a)(8) of this section, the number of natural gas pneumatic devices routed to flares, combustion, or vapor recovery systems, by type, must be reported as specified in § 98.236(b)(2)(iii).
                            </P>
                            <P>
                                (i) If any natural gas pneumatic devices were routed to a flare, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O emissions for the flare stack as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n).
                            </P>
                            <P>(ii) If emissions from any natural gas pneumatic devices were routed to combustion units, you must calculate and report emissions as specified in subpart C of this part or calculate emissions as specified in paragraph (z) of this section and report emissions from the combustion equipment as specified in § 98.236(z), as applicable.</P>
                            <HD SOURCE="HD3">(b) [Reserved]</HD>
                            <P>
                                (c) 
                                <E T="03">Natural gas driven pneumatic pump venting.</E>
                                 Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from natural gas driven pneumatic pumps venting directly to the atmosphere as specified in paragraph (c)(1), (2), or (3) of this section, as applicable. If you have a continuous flow meter on the natural gas supply line that is dedicated to any one or more natural gas driven pneumatic pumps, each of which only vents directly to the atmosphere, you must use Calculation Method 1 as specified in paragraph (c)(1) of this section to calculate vented CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from those pumps. Use Calculation Method 1 for any portion of a year when all of the pumps on the 
                                <PRTPAGE P="42243"/>
                                continuously measured natural gas supply line were vented directly to atmosphere. For natural gas driven pneumatic pumps vented directly to the atmosphere for which the natural gas supply rate is not continuously measured or the continuously measured natural gas supply line supplies some natural gas driven pneumatic pumps that vent emissions directly to the atmosphere and others that route emissions to flares, combustion or vapor recovery, use either the method specified in paragraph (c)(2) or (3) of this section to calculate vented CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions for all of the natural gas driven pneumatic pumps at your facility that are not subject to Calculation Method 1; you may not use Calculation Method 2 for some vented natural gas driven pneumatic pumps and Calculation Method 3 for other natural gas driven pneumatic pumps. Calculate emissions from natural gas driven pneumatic pumps routed to flares or combustion as specified in paragraph (c)(4) of this section. All references to natural gas driven pneumatic pumps for Calculation Method 1 in this paragraph (c) also apply to combinations of natural gas pneumatic devices and natural gas driven pneumatic pumps that are served by a common natural gas supply line. You do not have to calculate emissions from natural gas driven pneumatic pumps covered in paragraph (e) of this section under this paragraph (c).
                            </P>
                            <P>
                                (1) 
                                <E T="03">Calculation Method 1.</E>
                                 If you have or elect to install a continuous flow meter that is capable of meeting the requirements of § 98.234(b) of this subpart on a supply line to natural gas driven pneumatic pumps, then for the period of the year when the natural gas supply line is dedicated to any one or more natural gas driven pneumatic pumps, and each of the pumps is vented directly to the atmosphere, you must use the applicable methods specified in paragraphs (c)(1)(i) or (ii) of this section to calculate vented CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from those pumps.
                            </P>
                            <P>(i) For volumetric flow monitors:</P>
                            <P>(A) Determine the cumulative annual volumetric flow, in standard cubic feet, as measured by the flow monitor in the reporting year. If the flow meter was installed during the year, calculate the total volumetric flow for the year based on the measured volumetric flow times the total hours in the calendar year in which at least one of the pumps connected to the supply line was pumping liquid divided by the number of hours in the year when at least one of pumps connected to the supply line was pumping liquid and the volumetric flow was being measured.</P>
                            <P>
                                (B) Convert the natural gas volumetric flow from paragraph (c)(1)(i)(A) of this section to CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions following the provisions in paragraph (u) of this section.
                            </P>
                            <P>
                                (C) Convert the CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions from paragraph (c)(1)(i)(B) of this section to CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions using calculations in paragraph (v) of this section.
                            </P>
                            <P>(ii) For mass flow monitors:</P>
                            <P>(A) Determine the cumulative annual mass flow, in metric tons, as measured by the flow monitor in the reporting year. If the flow meter was installed during the year, calculate the total mass flow of vented natural gas emissions for the year based on the measured mass flow times the total hours in the calendar year in which at least one of the pumps connected to the supply line was pumping liquid divided by the number of hours in the year when at least one of pumps connected to the supply line was pumping liquid and the mass flow was being measured.</P>
                            <P>
                                (B) Convert the cumulative mass flow from paragraph (c)(1)(ii)(A) of this section to CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions by multiplying by the mass fraction of CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 in the supplied natural gas. You must follow the provisions in paragraph (u) of this section for determining the mole fraction of CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 and use molecular weights of 16 kg/kg-mol and 44 kg/kg-mol for CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                , respectively. You may assume unspecified components have an average molecular weight of 28 kg/kg-mol.
                            </P>
                            <P>(iii) If the supply line serves both natural gas pneumatic devices and natural gas driven pneumatic pumps, disaggregate the total measured amount of natural gas to natural gas pneumatic devices and natural gas driven pneumatic pumps based on engineering calculations and best available data.</P>
                            <P>(iv) The flow meter must be operated and calibrated according to the methods set forth in § 98.234(b).</P>
                            <P>
                                (2) 
                                <E T="03">Calculation Method 2.</E>
                                 Except as provided in paragraph (c)(1) of this section, you may elect to measure the volumetric flow rate of each natural gas driven pneumatic pump at your facility that vents directly to the atmosphere as specified in paragraphs (c)(2)(i) through (vii) of this section. You must exclude the counts of pumps measured according to paragraph (c)(1) of this section from the counts of pumps to be measured and for which emissions are calculated according to the requirements in this paragraph (c)(2).
                            </P>
                            <P>(i) Measure all natural gas driven pneumatic pumps at your facility at least once every 5 years. If you elect to measure your pneumatic pumps over multiple years, you must measure approximately the same number of pumps each year. When you measure the emissions from natural gas driven pneumatic pumps at a well-pad site or gathering and boosting site, you must measure all pneumatic pumps that are vented directly to the atmosphere at the well-pad site or gathering and boosting site during the same calendar year.</P>
                            <P>(ii) Determine the volumetric flow rate of each natural gas driven pneumatic pump (in standard cubic feet per hour) using one of the methods specified in § 98.234(b) through (d), as appropriate, according to the requirements specified in paragraphs (c)(2)(ii)(A) through (D) of this section. You must measure the emissions under representative conditions representative of normal operations, which excludes periods immediately after conducting maintenance on the pump.</P>
                            <P>(A) If you use a temporary meter, such as a vane anemometer, according to the methods set forth in § 98.234(b) or a high volume sampler according to methods set forth in § 98.234(d), you must measure the emissions from each pump for a minimum of 5 minutes, during a period when the pump is continuously pumping liquid.</P>
                            <P>(B) If you use calibrated bagging, follow the methods set forth in § 98.234(c), except under § 98.234(c)(2), only one bag must be filled to have a valid measurement. You must collect sample for a minimum of 5 minutes, or until the bag is full, whichever is shorter, during a period when the pump is continuously pumping liquid. If the bag is not full after 5 minutes, you must either continue sampling until you fill the calibrated bag or you may elect to remeasure the vent according to paragraph (c)(2)(ii)(A) of this section.</P>
                            <P>(C) You do not need to use the same measurement method for each natural gas driven pneumatic pump vent.</P>
                            <P>(D) If the measurement method selected measures the volumetric flow rate in actual cubic feet, convert the measured flow to standard cubic feet following the methods specified in paragraph (t)(1) of this section. Convert the measured flow during the test period to standard cubic feet per hour, as appropriate.</P>
                            <P>(iii) Calculate the volume of natural gas emitted from each natural gas driven pneumatic pump vent as the product of the natural gas emissions flow rate measured in paragraph (c)(2)(ii) of this section and the number of hours that liquid was pumped by the pneumatic pump in the calendar year.</P>
                            <P>
                                (iv) For each pneumatic pump, convert the volumetric emissions of natural gas at standard conditions 
                                <PRTPAGE P="42244"/>
                                determined in paragraph (c)(2)(iii) of this section to CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 volumetric emissions at standard conditions using the methods specified in paragraph (u) of this section.
                            </P>
                            <P>(v) For each pneumatic pump, convert the GHG volumetric emissions at standard conditions determined in paragraph (c)(2)(iv) of this section to GHG mass emissions using the methods specified in paragraph (v) of this section.</P>
                            <P>
                                (vi) Sum the CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 mass emissions determined in paragraph (c)(2)(v) of this section.
                            </P>
                            <P>(vii) If you chose to conduct natural gas pneumatic pump measurements over multiple years, “n,” according to paragraph (c)(2)(i) of this section, then you must calculate the emissions from all pneumatic pumps at your facility as specified in paragraph (c)(2)(vii)(A) through (D) of this section.</P>
                            <P>(A) Use the emissions calculated in paragraph (c)(2)(vi) of this section for the pumps measured during the reporting year.</P>
                            <P>
                                (B) Calculate the whole gas emission factor for pneumatic pumps at the facility using equation W-2A to this section and all available data from the current year and the previous years in your monitoring cycle (n-1 years) for which natural gas pneumatic pump vent measurements were made according to Calculation Method 2 in paragraph (c)(2) of this section (
                                <E T="03">e.g.</E>
                                , if your monitoring cycle is 3 years, then use measured data from the current year and the two previous years). This emission factor must be updated annually.
                            </P>
                            <GPH SPAN="3" DEEP="33">
                                <GID>ER14MY24.044</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">s</E>
                                     = Whole gas population emission factor for natural gas pneumatic pump vents, in standard cubic feet per hour per pump.
                                </FP>
                                <FP SOURCE="FP-2">
                                    MT
                                    <E T="52">s,y</E>
                                     = Volumetric whole gas emissions rate measurement at standard (“s”) conditions during year “y” in standard cubic feet per hour, as calculated in paragraph (c)(2)(iii) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Count
                                    <E T="52">y</E>
                                     = Count of natural gas driven pneumatic pump vents measured according to Calculation Method 2 in year “y.”
                                </FP>
                                <FP SOURCE="FP-2">n = Number of years of data to include in the emission factor calculation according to the number of years used to monitor all natural gas pneumatic pump vents at the facility.</FP>
                            </EXTRACT>
                            <P>
                                (C) Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions from natural gas driven pneumatic pumps per well-pad site or gathering and boosting site that were not measured during the reporting year using equation W-2B to this section.
                            </P>
                            <GPH SPAN="3" DEEP="14">
                                <GID>ER14MY24.045</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i</E>
                                     = Annual total volumetric GHG emissions at standard conditions in standard cubic feet per year from natural gas driven pneumatic pump vents, for GHG
                                    <E T="52">i</E>
                                    .
                                </FP>
                                <FP SOURCE="FP-2">Count = Total number of natural gas driven pneumatic pumps that vented directly to the atmosphere and that were not directly measured according to the requirements in paragraphs (c)(1) or (c)(2)(ii) of this section.</FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">s</E>
                                     = Population emission factors for natural gas driven pneumatic pumps (in standard cubic feet per hour per pump) as calculated using equation W-2A to this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i</E>
                                     = Concentration of GHG
                                    <E T="52">i</E>
                                    , CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    , in produced natural gas as defined in paragraph (u)(2)(i) of this section.
                                </FP>
                                <FP SOURCE="FP-2">T = Average estimated number of hours in the operating year the pumps that vented directly to the atmosphere were pumping liquid using engineering estimates based on best available data. Default is 8,760 hours for pumps that only vented directly to the atmosphere.</FP>
                            </EXTRACT>
                            <P>
                                (D) Calculate both CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions from volumetric emissions calculated using equation W-2B to this section using calculations in paragraph (v) of this section.
                            </P>
                            <P>
                                (E) Sum the CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions calculated in paragraphs (c)(2)(vii)(A) and (D) of this section to calculate the total CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions for Calculation Method 2 per well-pad site or gathering and boosting site.
                            </P>
                            <P>
                                (3) 
                                <E T="03">Calculation Method 3</E>
                                . If you elect not to measure emissions as specified in Calculation Method 2, then you must use the applicable method specified in paragraphs (c)(3)(i) and (ii) of this section to calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from all natural gas driven pneumatic pumps that are vented directly to the atmosphere at each well-pad site or gathering and boosting site at your facility and that are not measured according to paragraph (c)(1) of this section. You must exclude the counts of devices measured according to paragraph (c)(1) of this section from the counts of pumps for which emissions are calculated according to the requirements in this paragraph (c)(3).
                            </P>
                            <P>
                                (i) Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions from natural gas driven pneumatic pumps using equation W-2B to this section, except use the appropriate default whole gas population emission factor for natural gas pneumatic pump vents (in standard cubic feet per hour per device) as provided in table W-1 to this subpart.
                            </P>
                            <P>
                                (ii) Convert the CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions determined according to paragraph (c)(3)(i) of this section to CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 mass emissions using calculations in paragraph (v) of this section.
                            </P>
                            <P>
                                (4) 
                                <E T="03">Routing to flares, combustion, or vapor recovery systems</E>
                                . Calculate emissions from natural gas driven pneumatic pumps for periods when they are routed to flares or combustion as specified in paragraph (c)(4)(i) or (ii) of this section, as applicable. If emissions from a natural gas driven pneumatic pump were vented directly to the atmosphere for part of the year and routed to a flare, combustion, or vapor recovery for another part of the year, then calculate vented emissions for the portion of the year when venting occurs using the applicable method in paragraph (c)(1), (2), or (3) of this section for the period when venting occurs (including periods when emissions bypassed a flare), and calculate emissions for the portion of the year when the emissions are routed to a flare or combustion unit using the method in paragraph (c)(4) of this section. During periods when emissions from a pump are routed to a vapor recovery system without subsequently being routed to combustion, paragraphs (c)(1) through (3) and (c)(4)(i) and (ii) of this section do not apply and no emissions calculations are required. Notwithstanding the calculation and 
                                <PRTPAGE P="42245"/>
                                emissions reporting requirements as specified in this paragraph (c)(4) of this section, the number of natural gas pneumatic pumps routed to flares, combustion, or vapor recovery systems must be reported as specified in § 98.236(c)(2)(iii) and (iv).
                            </P>
                            <P>
                                (i) If any natural gas driven pneumatic pumps were routed to a flare, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O emissions for the flare stack as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n).
                            </P>
                            <P>(ii) If emissions from any natural gas driven pneumatic pumps were routed to combustion, you must calculate emissions for the combustion equipment as specified in paragraph (z) of this section and report emissions from the combustion equipment as specified in § 98.236(z).</P>
                            <P>
                                (d) 
                                <E T="03">Acid gas removal unit (AGR) vents and Nitrogen removal unit (NRU) vents</E>
                                . For AGR vents (including processes such as amine, membrane, molecular sieve or other absorbents and adsorbents), calculate emissions for CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 vented directly to the atmosphere or emitted through a sulfur recovery plant, using any of the calculation methods described in paragraphs (d)(1) through (4) of this section, and also comply with paragraphs (d)(5) through (12) of this section, as applicable. For NRU vents, calculate emissions for CH
                                <E T="52">4</E>
                                 vented directly to the atmosphere using any of the calculation methods described in paragraphs (d)(1) through (4) of this section, and also comply with paragraphs (d)(5) through (11) of this section, as applicable. If any AGR vents or NRU vents are routed to a flare, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O emissions for the flare stack as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n). If any AGR vents or NRU vents are routed through an engine (
                                <E T="03">e.g.,</E>
                                 permeate from a membrane or de-adsorbed gas from a pressure swing adsorber used as fuel supplement) (
                                <E T="03">i.e</E>
                                ., routed to combustion), you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O emissions as specified in subpart C of this part or as specified in paragraph (z) of this section, as applicable.
                            </P>
                            <P>
                                (1) 
                                <E T="03">Calculation Method 1</E>
                                . If you operate and maintain a continuous emissions monitoring system (CEMS) that has both a CO
                                <E T="52">2</E>
                                 concentration monitor and volumetric flow rate monitor, you must calculate CO
                                <E T="52">2</E>
                                 emissions under this subpart by following the Tier 4 Calculation Method and all associated calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). Alternatively, you may follow the manufacturer's instructions or industry standard practice. If a CO
                                <E T="52">2</E>
                                 concentration monitor and volumetric flow rate monitor are not available, you may elect to install a CO
                                <E T="52">2</E>
                                 concentration monitor and a volumetric flow rate monitor that comply with all of the requirements specified for the Tier 4 Calculation Method in subpart C of this part (General Stationary Fuel Combustion Sources).
                            </P>
                            <P>
                                (2) 
                                <E T="03">Calculation Method 2</E>
                                . Except as specified in paragraph (d)(4) of this section, for CO
                                <E T="52">2</E>
                                 emissions, if a CEMS is not available but a vent meter is installed, use the CO
                                <E T="52">2</E>
                                 composition and annual volume of vent gas to calculate emissions using equation W-3 to this section. Except as specified in paragraph (d)(4) of this section, for CH
                                <E T="52">4</E>
                                 emissions, if a vent meter is installed, including the volumetric flow rate monitor on a CEMS for CO
                                <E T="52">2</E>
                                , use the CH
                                <E T="52">4</E>
                                 composition and annual volume of vent gas to calculate emissions using equation W-3 to this section.
                            </P>
                            <GPH SPAN="3" DEEP="14">
                                <GID>ER14MY24.046</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">a,i</E>
                                     = Annual total volumetric GHGi (either CO
                                    <E T="52">2</E>
                                     or CH
                                    <E T="52">4</E>
                                    ) emissions at actual conditions, in cubic feet per year.
                                </FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">a</E>
                                     = Total annual volume of vent gas flowing out of the AGR or NRU in cubic feet per year at actual conditions as determined by flow meter using methods set forth in § 98.234(b). Alternatively, you may follow the manufacturer's instructions or industry standard practice for calibration of the vent meter.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Vol
                                    <E T="52">i</E>
                                     = Annual average volumetric fraction of GHGi (either CO
                                    <E T="52">2</E>
                                     or CH
                                    <E T="52">4</E>
                                    ) content in vent gas flowing out of the AGR or NRU as determined in paragraph (d)(7) of this section.
                                </FP>
                            </EXTRACT>
                            <P>
                                (3) 
                                <E T="03">Calculation Method 3</E>
                                . If a CEMS for CO
                                <E T="52">2</E>
                                 or a vent meter is not installed, you may use the inlet and/or outlet gas flow rate of the AGR or NRU to calculate emissions for CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 using equation W-4A, W-4B, or W-4C to this section. If inlet gas flow rate and CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 content of the vent gas are known, use equation W-4A to this section. If outlet gas flow rate and CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 content of the vent gas are known, use equation W-4B to this section. If inlet gas flow rate and outlet gas flow rate are known, use equation W-4C to this section. If the calculated annual total volumetric emissions (Ea,i) are less than or equal to 0 cubic feet per year, you may not use this calculation method for either CH
                                <E T="52">4</E>
                                 or CO
                                <E T="52">2</E>
                                .
                            </P>
                            <GPH SPAN="3" DEEP="29">
                                <GID>ER14MY24.047</GID>
                            </GPH>
                            <GPH SPAN="3" DEEP="29">
                                <GID>ER14MY24.048</GID>
                            </GPH>
                            <GPH SPAN="3" DEEP="18">
                                <GID>ER14MY24.049</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">a,i</E>
                                     = Annual total volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions at actual conditions, in cubic feet per year.
                                </FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">in</E>
                                     = Total annual volume of natural gas flow into the AGR or NRU in cubic feet per year at actual conditions as determined 
                                    <PRTPAGE P="42246"/>
                                    using methods specified in paragraph (d)(5) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">out</E>
                                     = Total annual volume of natural gas flow out of the AGR or NRU in cubic feet per year at actual conditions as determined using methods specified in paragraph (d)(5) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Vol
                                    <E T="52">I,i</E>
                                     = Annual average volumetric fraction of GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) content in natural gas flowing into the AGR or NRU as determined in paragraph (d)(7) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Vol
                                    <E T="52">O,i</E>
                                     = Annual average volumetric fraction of GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) content in natural gas flowing out of the AGR or NRU as determined in paragraph (d)(8) of this section.
                                </FP>
                                <P>
                                    Vol
                                    <E T="52">EM,i</E>
                                     = Annual average volumetric fraction of GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) content in the vent gas flowing out of the AGR or NRU as determined in paragraph (d)(6) of this section.
                                </P>
                            </EXTRACT>
                            <P>
                                (4) 
                                <E T="03">Calculation Method 4</E>
                                . If CEMS for CO
                                <E T="52">2</E>
                                 or a vent meter is not installed, you may calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from an AGR or NRU using any standard simulation software package, such as AspenTech HYSYS®, or API 4679 AMINECalc, that uses the Peng-Robinson equation of state and speciates CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions. A minimum of the parameters listed in paragraph (d)(4)(i) through (x) of this section, as applicable, must be used to characterize emissions. If paragraph (d)(4)(i) through (x) of this section indicates that an applicable parameter must be measured, collect measurements reflective of representative operating conditions over the time period covered by the simulation. Determine all other applicable parameters in paragraph (d)(4)(i) through (x) of this section by engineering estimate and process knowledge based on best available data and, if necessary, adjust parameters to represent the operating conditions over the time period covered by the simulation. Determine the number of simulations and associated time periods such that the simulations cover the entire reporting year (
                                <E T="03">i.e.</E>
                                , if you calculate emissions using one simulation, use representative parameters for the operating conditions over the calendar year; if you use periodic simulations to cover the calendar year, use parameters for the operating conditions over each corresponding appropriate portion of the calendar year). You may also use this method for CO
                                <E T="52">2</E>
                                 emissions from an AGR if a vent meter is installed but a CEMS is not, or for CH
                                <E T="52">4</E>
                                 emissions from an AGR if a vent meter is installed (including the volumetric flow rate monitor on a CEMS for CO
                                <E T="52">2</E>
                                ), in which case you must determine the difference between the annual volume of vent gas measured by the vent meter and the simulated annual volume of vent gas according to paragraph (d)(9) of this section.
                            </P>
                            <P>(i) Natural gas feed temperature, pressure, and flow rate (must be measured).</P>
                            <P>(ii) Acid gas content of feed natural gas (must be measured).</P>
                            <P>(iii) Acid gas content of outlet natural gas.</P>
                            <P>
                                (iv) CH
                                <E T="52">4</E>
                                 content of feed natural gas (must be measured).
                            </P>
                            <P>
                                (v) CH
                                <E T="52">4</E>
                                 content of outlet natural gas.
                            </P>
                            <P>(vi) For NRU, nitrogen content of feed natural gas (must be measured).</P>
                            <P>(vii) For NRU, nitrogen content of outlet natural gas.</P>
                            <P>(viii) Unit operating hours, excluding downtime for maintenance or standby.</P>
                            <P>(ix) Exit temperature of natural gas.</P>
                            <P>(x) For AGR, solvent type, pressure, temperature, circulation rate, and composition.</P>
                            <P>
                                (5) 
                                <E T="03">Flow rate of inlet or outlet</E>
                                . For Calculation Method 3, determine the gas flow rate of the inlet when using equation W-4A or W-4C to this section or the gas flow rate of the outlet when using equation W-4B or W-4C to this section for the natural gas stream of an AGR or NRU using a meter according to methods set forth in § 98.234(b). If you do not have a continuous flow meter, either install a continuous flow meter or use an engineering calculation to determine the flow rate.
                            </P>
                            <P>
                                (6) 
                                <E T="03">Composition of vent gas</E>
                                . For Calculation Method 2 or Calculation Method 3 when using equation W-4A or W-4B to this section, if a continuous gas analyzer is not available on the vent stack, either install a continuous gas analyzer or take quarterly gas samples from the vent gas stream for each quarter that the AGR or NRU is operating to determine Vol
                                <E T="52">i</E>
                                 in equation W-3 to this section or Vol
                                <E T="52">EM,i</E>
                                 in equation W-4A or W-4B to this section, according to the methods set forth in § 98.234(b).
                            </P>
                            <P>
                                (7) 
                                <E T="03">Composition of inlet gas stream</E>
                                . For Calculation Method 3, if a continuous gas analyzer is installed on the inlet gas stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, either install a continuous gas analyzer or take quarterly gas samples from the inlet gas stream for each quarter that the AGR or NRU is operating to determine VolI,i in equation W-4A, W-4B, or W-4C to this section, according to the methods set forth in § 98.234(b).
                            </P>
                            <P>
                                (8) 
                                <E T="03">Composition of outlet gas stream</E>
                                . For Calculation Method 3, determine annual average volumetric fraction of GHGi (either CH
                                <E T="52">4</E>
                                 or CO
                                <E T="52">2</E>
                                ) content in natural gas flowing out of the AGR or NRU using one of the methods specified in paragraphs (d)(8)(i) through (iii) of this section.
                            </P>
                            <P>(i) If a continuous gas analyzer is installed on the outlet natural gas stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, you may install a continuous gas analyzer.</P>
                            <P>
                                (ii) If a continuous gas analyzer is not available or installed, quarterly gas samples may be taken from the outlet natural gas stream for each quarter that the AGR or NRU is operating to determine Vol
                                <E T="52">O,i</E>
                                 in equation W-4A, W-4B, or W-4C to this section, according to the methods set forth in § 98.234(b).
                            </P>
                            <P>
                                (iii) If a continuous gas analyzer is not available or installed, you may use the outlet pipeline quality specification for CO
                                <E T="52">2</E>
                                 in natural gas and the outlet quality specification for CH
                                <E T="52">4</E>
                                 in natural gas.
                            </P>
                            <P>(9) Comparison of annual volume of vent gas. If a vent meter is installed but you wish to use Calculation Method 4 rather than Calculation Method 2 for an AGR, use equation W-4D to this section to determine the difference between the annual volume of vent gas measured by the vent meter and the simulated annual volume of vent gas.</P>
                            <GPH SPAN="3" DEEP="39">
                                <GID>ER14MY24.050</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">PD = Percent difference between vent gas volumes, %.</FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">a,meter</E>
                                     = Total annual volume of vent gas flowing out of the AGR in cubic feet per year at actual conditions as determined by flow meter using methods set forth in § 98.234(b). Alternatively, you may follow the manufacturer's instructions or industry standard practice for calibration of the vent meter.
                                </FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">a,sim</E>
                                     = Total annual volume of vent gas flowing out of the AGR in cubic feet per year at actual conditions as determined 
                                    <PRTPAGE P="42247"/>
                                    by a standard simulation software package consistent with paragraph (d)(4) of this section.
                                </FP>
                            </EXTRACT>
                            <P>
                                (10) 
                                <E T="03">Volumetric emissions</E>
                                . Calculate annual volumetric CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions at standard conditions using calculations in paragraph (t) of this section.
                            </P>
                            <P>
                                (11) 
                                <E T="03">Emissions vented directly to atmosphere from AGRs or NRUs routed to vapor recovery systems or flares</E>
                                . If the AGR vent or NRU vent has a vapor recovery system or routes emissions to a flare, calculate annual emissions vented directly to atmosphere from the AGR vent or NRU vent during periods of time when emissions were not routed to the vapor recovery system or flare as specified in paragraph (d)(11)(i) and (ii) of this section. If emissions are routed to a flare but the flare is unlit, calculate emissions in accordance with the methodology specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n).
                            </P>
                            <P>(i) Calculate vented emissions as specified in paragraph (d)(1), (2), (3), or (4) of this section, which represents the emissions from the AGR vent or NRU vent prior to the vapor recovery system or flare. Calculate an average hourly vented emissions rate by dividing the vented emissions by the number of hours that the AGR or NRU was in operation.</P>
                            <P>(ii) To calculate vented emissions during periods when the AGR vent or NRU vent was not routing emissions to a vapor recovery system or a flare, multiply the average hourly vented emissions rate determined in paragraph (d)(11)(i) of this section by the number of hours that the AGR or NRU vented directly to the atmosphere. Determine the number of hours that the AGR or NRU vented directly to atmosphere by subtracting the hours that the AGR or NRU was connected to a vapor recovery system or flare (based on engineering estimate and best available data) from the total operating hours for the AGR or NRU in the calendar year. You must take into account periods with reduced capture efficiency of the vapor recovery system or flare.</P>
                            <P>
                                (12) 
                                <E T="03">Mass emissions</E>
                                . Calculate annual mass CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions using calculations in paragraph (v) of this section.
                            </P>
                            <P>
                                (e) 
                                <E T="03">Dehydrator vents</E>
                                . For dehydrator vents, calculate annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions using the applicable calculation methods described in paragraphs (e)(1) through (5) of this section. For glycol dehydrators that have an annual average daily natural gas throughput that is greater than or equal to 0.4 million standard cubic feet per day, use Calculation Method 1 in paragraph (e)(1) of this section. For glycol dehydrators that have an annual average of daily natural gas throughput that is greater than 0 million standard cubic feet per day and less than 0.4 million standard cubic feet per day, use either Calculation Method 1 in paragraph (e)(1) of this section or Calculation Method 2 in paragraph (e)(2) of this section. If you are required to use a software program consistent with the requirements of paragraph (e)(1) of this section for compliance with federal or state regulations, air permit requirements, or annual emissions inventory reporting for the current reporting year, you must use Calculation Method 1 to calculate annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions. If emissions from dehydrator vents are routed to a vapor recovery system, you must calculate the emissions according to paragraph (e)(4) of this section. If emissions from dehydrator vents are routed to a regenerator firebox/fire tubes, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N2O annual emissions as specified in paragraph (e)(5) of this section. If any dehydrator vents are routed to a flare, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N2O emissions for the flare stack as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n).
                            </P>
                            <P>
                                (1) 
                                <E T="03">Calculation Method 1</E>
                                . Calculate annual mass emissions from glycol dehydrators by using a software program, such as AspenTech HYSYS®, Bryan Research &amp; Engineering ProMax@, or GRI-GLYCalcTM, that uses the Peng-Robinson equation of state to calculate the equilibrium coefficient, speciates CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from dehydrators, and has provisions to include regenerator control devices, a separator flash tank, stripping gas, and a gas injection pump or gas assist pump. If you elect to use ProMax@, you must use version 5.0 or above. Emissions must be modeled from both the still vent and, if applicable, the flash tank vent. A minimum of the parameters listed in paragraph (e)(1)(i) through (xi) of this section, as applicable, must be used to characterize emissions. If paragraph (e)(1)(i) through (xi) of this section indicates that an applicable parameter must be measured, collect measurements reflective of representative operating conditions for the time period covered by the simulation. Sample and analyze composition at least once every five years. Samples must be collected within six months of the startup or by January 1, 2030, whichever date is later. Until such a time that a sample is collected, determine composition by using one of the existing methods. Determine all other applicable parameters in paragraph (e)(1)(i) through (xi) of this section by engineering estimate and process knowledge based on best available data and, if necessary, adjust parameters to represent the operating conditions over the time period covered by the simulation. Determine the number of simulations and associated time periods such that the simulations cover the entire reporting year (i.e., if you calculate emissions using one simulation, use representative parameters for the operating conditions over the calendar year; if you use periodic simulations to cover the calendar year, use parameters for the operating conditions over each corresponding appropriate portion of the calendar year). If more than one simulation is performed, input parameters should be remeasured if no longer representative of operating conditions.
                            </P>
                            <P>(i) Feed natural gas flow rate (based on measured data).</P>
                            <P>(ii) Feed natural gas water content (must be measured).</P>
                            <P>(iii) Outlet natural gas water content.</P>
                            <P>(iv) Absorbent circulation pump type (e.g., natural gas pneumatic/air pneumatic/electric).</P>
                            <P>(v) Absorbent circulation rate.</P>
                            <P>(vi) Absorbent type (e.g., triethylene glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG)).</P>
                            <P>(vii) Use of stripping gas.</P>
                            <P>(viii) Use of flash tank separator (and disposition of recovered gas).</P>
                            <P>(ix) Hours operated.</P>
                            <P>(x) Wet natural gas temperature and pressure at the absorber inlet (must be measured).</P>
                            <P>(xi) Wet natural gas composition. Measure this parameter using one of the methods described in paragraphs (e)(1)(xi)(A) and (B) of this section.</P>
                            <P>(A) Use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as specified in § 98.234(b) to sample and analyze wet natural gas composition.</P>
                            <P>(B) If only composition data for dry natural gas is available, assume the wet natural gas is saturated.</P>
                            <P>
                                (2) 
                                <E T="03"/>
                                 . Calculate annual volumetric emissions from glycol dehydrators using equation W-5 to this section, and then calculate the collective CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions from the volumetric emissions using the procedures in paragraph (v) of this section:
                            </P>
                            <GPH SPAN="3" DEEP="20">
                                <PRTPAGE P="42248"/>
                                <GID>ER14MY24.051</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i</E>
                                     = Annual total volumetric GHG emissions (either CO
                                    <E T="52">2</E>
                                     or CH
                                    <E T="52">4</E>
                                    ) at standard conditions in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">i</E>
                                     = Population emission factors for glycol dehydrators in thousand standard cubic feet per dehydrator per year. Use 73.4 for CH
                                    <E T="52">4</E>
                                     and 3.21 for CO
                                    <E T="52">2</E>
                                     at 60 °F and 14.7 psia.
                                </FP>
                                <FP SOURCE="FP-2">Count = Total number of glycol dehydrators that have an annual average daily natural gas throughput that is greater than 0 million standard cubic feet per day and less than 0.4 million standard cubic feet per day for which you elect to use this Calculation Method 2.</FP>
                                <FP SOURCE="FP-2">1000 = Conversion of EFi in thousand standard cubic feet to standard cubic feet.</FP>
                            </EXTRACT>
                            <P>
                                (3) 
                                <E T="03">Calculation Method 3</E>
                                . For dehydrators of any size that use desiccant, you must calculate emissions from the amount of gas vented from the vessel when it is depressurized for the desiccant refilling process using equation W-6 to this section. From volumetric natural gas emissions, calculate both CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric and mass emissions using the procedures in paragraphs (u) and (v) of this section. Desiccant dehydrator emissions covered in this paragraph do not have to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks.
                            </P>
                            <GPH SPAN="3" DEEP="34">
                                <GID>ER14MY24.052</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,n</E>
                                     = Annual natural gas emissions at standard conditions in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">H = Height of the dehydrator vessel (ft).</FP>
                                <FP SOURCE="FP-2">D = Inside diameter of the vessel (ft).</FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">1</E>
                                     = Atmospheric pressure (psia).
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">2</E>
                                     = Pressure of the gas (psia).
                                </FP>
                                <FP SOURCE="FP-2">π = pi (3.14).</FP>
                                <FP SOURCE="FP-2">%G = Percent of packed vessel volume that is gas.</FP>
                                <FP SOURCE="FP-2">N = Number of dehydrator openings in the calendar year.</FP>
                                <FP SOURCE="FP-2">100 = Conversion of %G to fraction.</FP>
                            </EXTRACT>
                            <P>
                                (4) 
                                <E T="03">Emissions vented directly to atmosphere from dehydrators routed to a vapor recovery system, flare, or regenerator firebox/fire tubes.</E>
                                 If the dehydrator(s) has a vapor recovery system, routes emissions to a flare, or routes emissions to a regenerator firebox/fire tubes and you use Calculation Method 1 or Calculation Method 2 in paragraph (e)(1) or (2) of this section, calculate annual emissions vented directly to atmosphere from the dehydrator(s) during periods of time when emissions were not routed to the vapor recovery system, flare, or regenerator firebox/fire tubes as specified in paragraphs (e)(4)(i) and (ii) of this section. If the dehydrator(s) has a vapor recovery system or routes emissions to a flare and you use Calculation Method 3 in paragraph (e)(3) of this section, calculate annual emissions vented directly to atmosphere from the dehydrator(s) during periods of time when emissions were not routed to the vapor recovery system or flare as specified in paragraph (e)(4)(iii) of this section.
                            </P>
                            <P>(i) When emissions from dehydrator(s) are calculated using Calculation Method 1 or 2, calculate vented emissions as specified in paragraph (e)(1) or (2) of this section, which represents the emissions from the dehydrator prior to the vapor recovery system or flare. Calculate an average hourly vented emissions rate by dividing the vented emissions by the number of hours that the dehydrator was in operation.</P>
                            <P>(ii) To calculate total emissions vented directly to atmosphere during periods when the dehydrator was not routing emissions to a vapor recovery system, flare, or regenerator firebox/fire tubes for dehydrator(s) with emissions calculated using Calculation Method 1 or 2, multiply the average hourly vented emissions rate determined in paragraph (e)(4)(i) of this section by the number of hours that the dehydrator vented directly to the atmosphere. Determine the number of hours that the dehydrator vented directly to atmosphere by subtracting the hours that the dehydrator was connected to a vapor recovery system, flare, or regenerator firebox/fire tubes (based on engineering estimate and best available data) from the total operating hours for the dehydrator in the calendar year. You must take into account periods with reduced capture efficiency of the vapor recovery system, flare, or regenerator firebox/fire tubes. If emissions are routed to a flare but the flare is unlit, calculate emissions in accordance with the methodology specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n).</P>
                            <P>(iii) When emissions from dehydrator(s) are calculated using Calculation Method 3, calculate total annual emissions vented directly to atmosphere from the dehydrator(s) during periods of time when emissions were not routed to the vapor recovery system, flare, or regenerator firebox/fire tubes by determining of the number of depressurization events (including portions of an event) that vented to atmosphere based on engineering estimate and best available data. You must take into account periods with reduced capture efficiency of the vapor recovery system or flare. If emissions are routed to a flare but the flare is unlit, calculate emissions in accordance with the methodology specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n).</P>
                            <P>
                                (5) 
                                <E T="03">Combustion emissions from routing to regenerator firebox/fire tubes or other non-flare combustion unit.</E>
                                 If any glycol dehydrator emissions are routed to a regenerator firebox/fire tubes or other non-flare combustion unit, calculate emissions from these devices attributable to dehydrator flash tank vents or still vents as specified in paragraphs (e)(5)(i) through (iii) of this section. If any desiccant dehydrator emissions are routed to a non-flare combustion unit, calculate combusted emissions as specified in paragraphs (e)(5)(i) through (iii) of this section. If you operate a CEMS to monitor the emissions from the regenerator firebox/fire tubes or other non-flare combustion unit, calculate emissions as specified in paragraph (e)(5)(iv) of this section.
                            </P>
                            <P>(i) Determine the volume of the total emissions that is routed to a regenerator firebox/fire tubes or other non-flare combustion unit as specified in paragraph (e)(5)(i)(A) or (B) of this section.</P>
                            <P>
                                (A) Measure the flow from the dehydrator(s) to the regenerator firebox/fire tubes or other non-flare combustion unit using a continuous flow measurement device. If you continuously measure flow to the 
                                <PRTPAGE P="42249"/>
                                regenerator firebox/fire tubes or other non-flare combustion unit, you must use the measured volumes to calculate emissions from the regenerator firebox/fire tubes or other non-flare combustion unit.
                            </P>
                            <P>(B) Using engineering estimates based on best available data, determine the volume of the total emissions estimated in paragraph (e)(1), (2), or (3) of this section, as applicable, that is routed to the regenerator firebox/fire tubes or other non-flare combustion unit.</P>
                            <P>(ii) Determine composition of the gas routed to a regenerator firebox/fire tubes or other non-flare combustion unit as specified in paragraph (e)(5)(ii)(A) or (B) of this section.</P>
                            <P>(A) Use the appropriate vent emissions as determined in paragraph (e)(1) or (2) of this section.</P>
                            <P>(B) Measure the composition of the gas from the dehydrator(s) to the regenerator firebox/fire tubes or other non-flare combustion unit using a continuous composition analyzer. If you continuously measure gas composition, then those measured data must be used to calculate dehydrator emissions from the regenerator firebox/fire tubes.</P>
                            <P>(iii) Determine GHG volumetric emissions at actual conditions from the regenerator firebox/fire tubes or other non-flare combustion unit using equations W-39A, W-39B, and W-40 to this section. Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section. Calculate both GHG mass emissions from volumetric emissions using calculations in paragraph (v) of this section.</P>
                            <P>
                                (iv) If you operate and maintain a CEMS that has both a CO
                                <E T="52">2</E>
                                 concentration monitor and volumetric flow rate monitor for the combustion gases from the regenerator firebox/fire tubes or other non-flare combustion unit, you must calculate only CO
                                <E T="52">2</E>
                                 emissions for the regenerator firebox/fire tubes. You must follow the Tier 4 Calculation Method and all associated calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). If a CEMS is used to calculate emissions from a regenerator firebox/fire tubes or other non-flare combustion unit, the requirements specified in paragraphs (e)(5)(ii) and (iii) of this section are not required.
                            </P>
                            <P>
                                (f) 
                                <E T="03">Well venting for liquids unloadings.</E>
                                 Calculate annual volumetric natural gas emissions from well venting for liquids unloading when the well is unloaded to the atmosphere using one of the calculation methods described in paragraph (f)(1), (2), or (3) of this section. Calculate annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric and mass emissions using the method described in paragraph (f)(4) of this section. If emissions from well venting for liquids unloading are routed to a flare, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O annual emissions as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n).
                            </P>
                            <P>
                                (1) 
                                <E T="03">Calculation Method 1.</E>
                                 Calculate emissions from manual and automated unloadings at wells with plunger lifts and wells without plunger lifts separately. For at least one well of each unique well tubing diameter group and pressure group combination in each sub-basin category (see § 98.238 for the definitions of tubing diameter group, pressure group, and sub-basin category), where gas wells are vented directly to the atmosphere to expel liquids accumulated in the tubing, install a recording flow meter on the vent line used to vent gas from the well (e.g., on the vent line off the wellhead separator or atmospheric storage tank) according to methods set forth in § 98.234(b). Calculate the total emissions from well venting to the atmosphere for liquids unloading using equation W-7A to this section. Equation W-7A to this section must be used for each unloading type combination (automated plunger lift unloadings, manual plunger lift unloadings, automated unloadings without plunger lifts and manual unloadings without plunger lifts) for any tubing diameter group and pressure group combination in each sub-basin.
                            </P>
                            <GPH SPAN="3" DEEP="16">
                                <GID>ER14MY24.053</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">a</E>
                                     = Annual natural gas emissions for each well of the same tubing diameter group and pressure group combination in the sub-basin at actual conditions, a, in cubic feet. Calculate emissions from wells with automated plunger lift unloadings, wells with manual plunger lift unloadings, wells with automated unloadings without plunger lifts and wells with manual unloadings without plunger lifts separately.
                                </FP>
                                <FP SOURCE="FP-2">FR = Average flow rate in cubic feet per hour for all measured wells of the same tubing diameter group and pressure group combination in a sub-basin, over the duration of the liquids unloading, under actual conditions as determined in paragraph (f)(1)(i) of this section.</FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">p</E>
                                     = Cumulative amount of time in hours of venting for each well, p, of the same tubing diameter group and pressure group combination in a sub-basin during the year. If the available venting data do not contain a record of the date of the venting events and data are not available to provide the venting hours for the specific time period of January 1 to December 31, you may calculate an annualized vent time, Tp, using equation W-7B to this section.
                                </FP>
                            </EXTRACT>
                            <GPH SPAN="3" DEEP="33">
                                <GID>ER14MY24.054</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    HR
                                    <E T="52">p</E>
                                     = Cumulative amount of time in hours of venting for each well, p, during the monitoring period.
                                </FP>
                                <FP SOURCE="FP-2">
                                    MP
                                    <E T="52">p</E>
                                     = Time period, in days, of the monitoring period for each well, p. A minimum of 300 days in a calendar year are required. The next period of data collection must start immediately following the end of data collection for the previous reporting year.
                                </FP>
                                <FP SOURCE="FP-2">
                                    D
                                    <E T="52">p</E>
                                     = Time period, in days during which the well, p, was in production (365 if the well was in production for the entire year).
                                </FP>
                            </EXTRACT>
                            <P>(i) Determine the well vent average flow rate (“FR” in equation W-7A to this section) as specified in paragraphs (f)(1)(i)(A) through (C) of this section for at least one well in a unique well tubing diameter group and pressure group combination in each sub-basin category. Calculate emissions from wells with automated plunger lift unloadings, wells with manual plunger lift unloadings, wells with automated unloadings without plunger lifts and wells with manual unloadings without plunger lifts separately.</P>
                            <P>
                                (A) Calculate the average flow rate per hour of venting for each unique tubing 
                                <PRTPAGE P="42250"/>
                                diameter group and pressure group combination in each sub-basin category by dividing the recorded total annual flow by the recorded time (in hours) for all measured liquid unloading events with venting to the atmosphere.
                            </P>
                            <P>(B) Apply the average hourly flow rate calculated under paragraph (f)(1)(i)(A) of this section to each well in the same pressure group that have the same tubing diameter group, for the number of hours of each well is venting to the atmosphere.</P>
                            <P>(C) Calculate a new average flow rate every other calendar year starting with the first calendar year of data collection. For a new producing sub-basin category, calculate an average flow rate beginning in the first year of production.</P>
                            <P>(ii) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section.</P>
                            <P>
                                (2) 
                                <E T="03">Calculation Method 2</E>
                                . Calculate the total emissions for each well from manual and automated well venting to the atmosphere for liquids unloading without plunger lift assist using equation W-8 to this section.
                            </P>
                            <GPH SPAN="3" DEEP="45">
                                <GID>ER14MY24.055</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s</E>
                                     = Annual natural gas emissions for each well at standard conditions, s, in cubic feet per year
                                </FP>
                                <FP SOURCE="FP-2">
                                    N
                                    <E T="52">p</E>
                                     = Total number of unloading events in the monitoring period per well, p.
                                </FP>
                                <FP SOURCE="FP-2">
                                    0.37×10
                                    <E T="51">−3</E>
                                     = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet).
                                </FP>
                                <FP SOURCE="FP-2">
                                    CD
                                    <E T="52">p</E>
                                     = Casing internal diameter for well, p, in inches or the tubing diameter for well, p, when stoppage packers are used in the annulus to restrict flow of gas up the annulus to the surface.
                                </FP>
                                <FP SOURCE="FP-2">
                                    WD
                                    <E T="52">p</E>
                                     = Vertical well depth from either the top of the well or the lowest packer to the bottom of the well or the top of the fluid column, for well, p, in feet. For horizontal wells the bottom of the well is the point at which the vertical borehole pivots to a horizontal direction.
                                </FP>
                                <FP SOURCE="FP-2">
                                    SP
                                    <E T="52">p</E>
                                     = For well, p, shut-in pressure or surface pressure for wells with tubing production, or casing pressure for each well with no packers, in pounds per square inch absolute (psia). If casing pressure is not available for the well, you may determine the casing pressure by multiplying the tubing pressure of the well with a ratio of casing pressure to tubing pressure from a well in the same sub-basin for which the casing pressure is known. The tubing pressure must be measured during gas flow to a flow-line. The shut-in pressure, surface pressure, or casing pressure must be determined just prior to liquids unloading when the well production is impeded by liquids loading or closed to the flow-line by surface valves.
                                </FP>
                                <FP SOURCE="FP-2">
                                    SFR
                                    <E T="52">p</E>
                                     = Average flow-line rate of gas for well, p, at standard conditions in cubic feet per hour. Use equation W-33 to this section to calculate the average flow-line rate at standard conditions.
                                </FP>
                                <FP SOURCE="FP-2">
                                    HR
                                    <E T="52">p,q</E>
                                     = Hours that well, p, was left open to the atmosphere during each unloading event, q.
                                </FP>
                                <FP SOURCE="FP-2">1.0 = Hours for average well to blowdown casing volume at shut-in pressure.</FP>
                                <FP SOURCE="FP-2">q = Unloading event.</FP>
                                <FP SOURCE="FP-2">
                                    Z
                                    <E T="52">p,q</E>
                                     = If HRp,q is less than 1.0 then Zp,q is equal to 0. If HRp,q is greater than or equal to 1.0 then Zp,q is equal to 1.
                                </FP>
                            </EXTRACT>
                            <P>(3) Calculation Method 3. Calculate the total emissions for each sub-basin from well venting to the atmosphere for liquids unloading with plunger lift assist using equation W-9 to this section.</P>
                            <GPH SPAN="3" DEEP="44">
                                <GID>ER14MY24.056</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s</E>
                                     = Annual natural gas emissions for each well at standard conditions, s, in cubic feet per year.
                                </FP>
                                <FP SOURCE="FP-2">
                                    N
                                    <E T="52">p</E>
                                     = Total number of unloading events in the monitoring period per well, p.
                                </FP>
                                <FP SOURCE="FP-2">
                                    0.37×10
                                    <E T="51">−3</E>
                                     = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet).
                                </FP>
                                <FP SOURCE="FP-2">
                                    TD
                                    <E T="52">p</E>
                                     = Tubing internal diameter for well, p, in inches.
                                </FP>
                                <FP SOURCE="FP-2">
                                    WD
                                    <E T="52">p</E>
                                     = Tubing depth to plunger bumper or to the top of the fluid column for well, p, in feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    SP
                                    <E T="52">p</E>
                                     = Flow-line pressure for well p in pounds per square inch absolute (psia), using engineering estimate based on best available data.
                                </FP>
                                <FP SOURCE="FP-2">
                                    SFR
                                    <E T="52">p</E>
                                     = Average flow-line rate of gas for well, p, at standard conditions in cubic feet per hour. Use equation W-33 to this section to calculate the average flow-line rate at standard conditions.
                                </FP>
                                <FP SOURCE="FP-2">
                                    HR
                                    <E T="52">p,q</E>
                                     = Hours that well, p, was left open to the atmosphere during each unloading event, q.
                                </FP>
                                <FP SOURCE="FP-2">0.5 = Hours for average well to blowdown tubing volume at flow-line pressure.</FP>
                                <FP SOURCE="FP-2">q = Unloading event.</FP>
                                <FP SOURCE="FP-2">
                                    Z
                                    <E T="52">p,q</E>
                                     = If HR
                                    <E T="52">p,q</E>
                                     is less than 0.5 then Z
                                    <E T="52">p,q</E>
                                     is equal to 0. If HR
                                    <E T="52">p,q</E>
                                     is greater than or equal to 0.5 then Z
                                    <E T="52">p,q</E>
                                     is equal to 1.
                                </FP>
                            </EXTRACT>
                            <P>
                                (4) 
                                <E T="03">Volumetric and mass emissions</E>
                                . Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section.
                            </P>
                            <P>
                                (g) 
                                <E T="03">Well venting during completions and workovers with hydraulic fracturing</E>
                                . Calculate annual volumetric natural gas emissions from gas well and oil well venting during completions and workovers involving hydraulic fracturing using equation W-10A or equation W-10B to this section. Equation W-10A to this section applies to well venting when the gas flowback rate is measured from a specified number of example completions or workovers in a sub-basin and well type combination and equation W-10B to this section applies when the gas flowback vent volume is measured for each completion or workover in a sub-basin and well type combination. Completion and workover activities are separated into two periods, an initial period when flowback is routed to open pits or tanks and a subsequent period when gas content is sufficient to route the flowback to a separator or when the gas content is sufficient to allow measurement by the devices specified in paragraph (g)(1) of this section, regardless of whether a separator is actually utilized. If you elect to use equation W-10A to this section, you must follow the procedures specified in paragraph (g)(1) of this section. If you elect to use equation W-10B to this section, you must use a recording flow meter installed on the vent line, downstream of a separator and ahead of 
                                <PRTPAGE P="42251"/>
                                a flare or vent, to measure the gas flowback. To calculate emissions during the initial period, you must calculate the gas flowback rate in the initial flowback period as described in equation W-10B to this section. Alternatively, you may use a multiphase flow meter placed on the flow line downstream of the wellhead and ahead of the separator to directly measure gas flowback during the initial period when flowback is routed to open pits or tanks. If you use a multiphase flow meter, measurements must be taken from initiation of flowback to the beginning of the period of time when sufficient quantities of gas are present to enable separation. For either equation, emissions must be calculated separately for completions and workovers, for each sub-basin, and for each well type combination identified in paragraph (g)(2) of this section. You must calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric and mass emissions as specified in paragraph (g)(3) of this section. If emissions from well venting during completions and workovers with hydraulic fracturing are routed to a flare, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O annual emissions as specified in paragraph (n) of this section, report emissions from the flare as specified in § 98.236(n), and report additional information specified in § 98.236(g), as applicable.
                            </P>
                            <GPH SPAN="3" DEEP="41">
                                <GID>ER14MY24.057</GID>
                            </GPH>
                            <GPH SPAN="3" DEEP="41">
                                <GID>ER14MY24.058</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,n</E>
                                     = Annual volumetric natural gas emissions in standard cubic feet from gas venting during well completions or workovers following hydraulic fracturing for each well.
                                </FP>
                                <FP SOURCE="FP-2">CW = Total number of completions or workovers using hydraulic fracturing.</FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">p,s</E>
                                     = Cumulative amount of time of flowback, after sufficient quantities of gas are present to enable separation, where gas vented for each completion or workover, in hours, during the reporting year. This may include non-contiguous periods of venting.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">p,i</E>
                                     = Cumulative amount of time of flowback to open tanks/pits, from when gas is first detected until sufficient quantities of gas are present to enable separation, for each completion or workover, in hours, during the reporting year. This may include non-contiguous periods of routing to open tanks/pits but does not include periods when the oil well ceases to produce fluids to the surface.
                                </FP>
                                <FP SOURCE="FP-2">
                                    FRM
                                    <E T="52">s</E>
                                     = Ratio of average gas flowback, during the period when sufficient quantities of gas are present to enable separation, of well completions and workovers from hydraulic fracturing to 30-day production rate for the sub-basin and well type combination, calculated using procedures specified in paragraph (g)(1)(iii) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    FRM
                                    <E T="52">i</E>
                                     = Ratio of initial gas flowback rate during well completions and workovers from hydraulic fracturing to 30-day gas production rate for the sub-basin and well type combination, calculated using procedures specified in paragraph (g)(1)(iv) of this section, for the period of flow to open tanks/pits.
                                </FP>
                                <FP SOURCE="FP-2">
                                    PR
                                    <E T="52">s,p</E>
                                     = Average gas production flow rate during the first 30 days of production after each completion of a newly drilled well or well workover using hydraulic fracturing in standard cubic feet per hour that was measured in the sub-basin and well type combination. If applicable, PRs,p may be calculated for oil wells using procedures specified in paragraph (g)(1)(vii) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EnF
                                    <E T="52">s,p</E>
                                     = Volume of N2 injected gas in cubic feet at standard conditions that was injected into the reservoir during an energized fracture job or during flowback during each completion or workover, as determined by using an appropriate meter according to methods described in § 98.234(b), or by using receipts of gas purchases that are used for the energized fracture job or injection during flowback. Convert to standard conditions using paragraph (t) of this section. If the fracture process did not inject gas into the reservoir or if the injected gas is CO
                                    <E T="52">2</E>
                                     then EnFs,p is 0.
                                </FP>
                                <FP SOURCE="FP-2">
                                    FV
                                    <E T="52">s,p</E>
                                     = Flow volume of vented gas for each completion or workover, in standard cubic feet measured using a recording flow meter (digital or analog) on the vent line to measure gas flowback during the separation period of the completion or workover according to methods set forth in § 98.234(b).
                                </FP>
                                <FP SOURCE="FP-2">
                                    FR
                                    <E T="52">p,i</E>
                                     = Flow rate vented of each completion or workover, in standard cubic feet per hour during the initial period when flowback is routed to open pits or tanks from initiation of flowback to the beginning of the period of time when sufficient quantities of gas are present to enable separation, measured using a recording flow meter (digital or analog) on the vent line to measure the flowback, at the beginning of the period of time when sufficient quantities of gas are present to enable separation, of the completion or workover according to methods set forth in § 98.234(b). Alternatively, flow rate during the initial period may be measured using a multiphase flow meter installed upstream of the separator capable of accurately measuring gas flow prior to separation.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Z
                                    <E T="52">p,i</E>
                                     = If a multiphase flow meter is used to measure flowback during the initial period, then Z
                                    <E T="52">p,i</E>
                                     is equal to 1. If flowback is measured using a recording flow meter (digital or analog) on the vent line to measure the flowback, at the beginning of the period of time when sufficient quantities of gas are present to enable separation, then Z
                                    <E T="52">p,i</E>
                                     is equal to 0.5.
                                </FP>
                            </EXTRACT>
                            <P>
                                (1) If you elect to use equation W-10A to this section on gas wells, you must use Calculation Method 1 as specified in paragraph (g)(1)(i) of this section. If you are unable to measure the gas flowback rates using a recording flow meter for gas well completions or workovers as described in Calculation Method 1, for example due to field conditions, operating conditions, or health and safety considerations, you may use Calculation Method 2 as specified in paragraph (g)(1)(ii) of this section to determine the value of FRM
                                <E T="52">s</E>
                                 and FRM
                                <E T="52">i</E>
                                . These values must be based on the flow rate for flowback gases, once sufficient gas is present to enable separation. The number of measurements or calculations required to estimate FRM
                                <E T="52">s</E>
                                 and FRM
                                <E T="52">i</E>
                                 must be determined individually for completions and workovers per sub-basin and well type combination as follows: Complete measurements or calculations for at least one completion or workover for less than or equal to 25 completions or workovers for each well type combination within a sub-basin; complete measurements or calculations for at least two completions or workovers for 26 to 50 completions or workovers for each sub-basin and well type combination; complete 
                                <PRTPAGE P="42252"/>
                                measurements or calculations for at least three completions or workovers for 51 to 100 completions or workovers for each sub-basin and well type combination; complete measurements or calculations for at least four completions or workovers for 101 to 250 completions or workovers for each sub-basin and well type combination; and complete measurements or calculations for at least five completions or workovers for greater than 250 completions or workovers for each sub-basin and well type combination.
                            </P>
                            <P>
                                (i) 
                                <E T="03">Calculation Method 1</E>
                                . You must use equation W-12A to this section as specified in paragraph (g)(1)(iii) of this section to determine the value of FRM
                                <E T="52">s</E>
                                . You must use equation W-12B to this section as specified in paragraph (g)(1)(iv) of this section to determine the value of FRM
                                <E T="52">i</E>
                                . The procedures specified in paragraphs (g)(1)(v) and (vi) of this section also apply. When making gas flowback measurements for use in equations W-12A and W-12B to this section, you must use a recording flow meter (digital or analog) installed on the vent line, downstream of a separator and ahead of a flare or vent, to measure the gas flowback rates in units of standard cubic feet per hour according to methods set forth in § 98.234(b). Alternatively, you may use a multiphase flow meter placed on the flow line downstream of the wellhead and ahead of the separator to directly measure gas flowback during the initial period when flowback is routed to open pits or tanks. If you use a multiphase flow meter, measurements must be taken from initiation of flowback to the beginning of the period of time when sufficient quantities of gas are present to enable separation.
                            </P>
                            <P>
                                (ii) 
                                <E T="03">Calculation Method 2 (for gas wells)</E>
                                . You must use equation W-12A to this section as specified in paragraph (g)(1)(iii) of this section to determine the value of FRM
                                <E T="52">s</E>
                                . You must use equation W-12B to this section as specified in paragraph (g)(1)(iv) of this section to determine the value of FRM
                                <E T="52">i</E>
                                . The procedures specified in paragraphs (g)(1)(v) and (vi) also apply. When calculating the flowback rates for use in equations W-12A and W-12B to this section based on well parameters, you must record the well flowing pressure immediately upstream (and immediately downstream in subsonic flow) of a well choke according to methods set forth in § 98.234(b) to calculate the well flowback. The upstream pressure must be surface pressure and reservoir pressure cannot be assumed. The downstream pressure must be measured after the choke and atmospheric pressure cannot be assumed. Calculate flowback rate using equation W-11A to this section for subsonic flow or equation W-11B to this section for sonic flow. You must use best engineering estimates based on best available data along with equation W-11C to this section to determine whether the predominant flow is sonic or subsonic. If the value of R in equation W-11C to this section is greater than or equal to 2, then flow is sonic; otherwise, flow is subsonic. Convert calculated FR
                                <E T="52">a</E>
                                 values from actual conditions upstream of the restriction orifice to standard conditions (FR
                                <E T="52">s,p</E>
                                 and FR
                                <E T="52">i,p</E>
                                ) for use in equations W-12A and W-12B to this section using equation W-33 to this section.
                            </P>
                            <GPH SPAN="3" DEEP="47">
                                <GID>ER14MY24.059</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    FR
                                    <E T="52">a</E>
                                     = Flowback rate in actual cubic feet per hour, under actual subsonic flow conditions.
                                </FP>
                                <FP SOURCE="FP-2">
                                    A = Cross sectional open area of the restriction orifice (m
                                    <E T="51">2</E>
                                    ).
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">1</E>
                                     = Pressure immediately upstream of the choke (psia).
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">u</E>
                                     = Temperature immediately upstream of the choke (degrees Kelvin).
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">2</E>
                                     = Pressure immediately downstream of the choke (psia).
                                </FP>
                                <FP SOURCE="FP-2">
                                    3430 = Constant with units of m
                                    <E T="51">2</E>
                                    /(sec
                                    <E T="51">2</E>
                                     * K).
                                </FP>
                                <FP SOURCE="FP-2">
                                    1.27*10
                                    <E T="51">5</E>
                                     = Conversion from m
                                    <E T="51">3</E>
                                    /second to ft
                                    <E T="51">3</E>
                                    /hour.
                                </FP>
                            </EXTRACT>
                            <GPH SPAN="3" DEEP="17">
                                <GID>ER14MY24.060</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    FR
                                    <E T="52">a</E>
                                     = Flowback rate in actual cubic feet per hour, under actual sonic flow conditions.
                                </FP>
                                <FP SOURCE="FP-2">
                                    A = Cross sectional open area of the restriction orifice (m
                                    <E T="51">2</E>
                                    ).
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">u</E>
                                     = Temperature immediately upstream of the choke (degrees Kelvin).
                                </FP>
                                <FP SOURCE="FP-2">
                                    187.08 = Constant with units of m
                                    <E T="51">2</E>
                                    /(sec
                                    <E T="51">2</E>
                                     * K).
                                </FP>
                                <FP SOURCE="FP-2">
                                    1.27*10
                                    <E T="51">5</E>
                                     = Conversion from m
                                    <E T="51">3</E>
                                    /second to ft
                                    <E T="51">3</E>
                                    /hour.
                                </FP>
                            </EXTRACT>
                            <GPH SPAN="3" DEEP="23">
                                <GID>ER14MY24.061</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">R = Pressure ratio.</FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">1</E>
                                     = Pressure immediately upstream of the choke (psia).
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">2</E>
                                     = Pressure immediately downstream of the choke (psia).
                                </FP>
                            </EXTRACT>
                            <P>(iii) For equation W-10A to this section, calculate FRMs using equation W-12A to this section.</P>
                            <GPH SPAN="3" DEEP="60">
                                <PRTPAGE P="42253"/>
                                <GID>ER14MY24.062</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    FRM
                                    <E T="52">s</E>
                                     = Ratio of average gas flowback rate, during the period of time when sufficient quantities of gas are present to enable separation, of well completions and workovers from hydraulic fracturing to 30-day gas production rate for each sub-basin and well type combination.
                                </FP>
                                <FP SOURCE="FP-2">
                                    FR
                                    <E T="52">s,p</E>
                                     = Measured average gas flowback rate from Calculation Method 1 described in paragraph (g)(1)(i) of this section or calculated average flowback rate from Calculation Method 2 described in paragraph (g)(1)(ii) of this section, during the separation period in standard cubic feet per hour for well(s) p for each sub-basin and well type combination. Convert measured and calculated FR
                                    <E T="52">a</E>
                                     values from actual conditions upstream of the restriction orifice (FR
                                    <E T="52">a</E>
                                    ) to standard conditions (FR
                                    <E T="52">s,p</E>
                                    ) for each well p using equation W-33 to this section. You may not use flow volume as used in equation W-10B to this section converted to a flow rate for this parameter.
                                </FP>
                                <FP SOURCE="FP-2">
                                    PR
                                    <E T="52">s,p</E>
                                     = Average gas production flow rate during the first 30 days of production after completions of newly drilled wells or well workovers using hydraulic fracturing, in standard cubic feet per hour for each well, p, that was measured in the sub-basin and well type combination. For oil wells for which production is not measured continuously during the first 30 days of production, the average flow rate may be based on individual well production tests conducted within the first 30 days of production. Alternatively, if applicable, PR
                                    <E T="52">s,p</E>
                                     may be calculated for oil wells using procedures specified in paragraph (g)(1)(vii) of this section.
                                </FP>
                                <FP SOURCE="FP-2">N = Number of measured or calculated well completions or workovers using hydraulic fracturing in a sub-basin and well type combination.</FP>
                            </EXTRACT>
                            <P>(iv) For equation W-10A to this section, calculate FRMi using equation W-12B to this section.</P>
                            <GPH SPAN="3" DEEP="66">
                                <GID>ER14MY24.063</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    FRM
                                    <E T="52">i</E>
                                     = Ratio of initial gas flowback rate during well completions and workovers from hydraulic fracturing to 30-day gas production rate for the sub-basin and well type combination, for the period of flow to open tanks/pits.
                                </FP>
                                <FP SOURCE="FP-2">
                                    FR
                                    <E T="52">i,p</E>
                                     = Initial measured gas flowback rate from Calculation Method 1 described in paragraph (g)(1)(i) of this section or initial calculated flow rate from Calculation Method 2 described in paragraph (g)(1)(ii) of this section in standard cubic feet per hour for well(s), p, for each sub-basin and well type combination. Measured and calculated FR
                                    <E T="52">i,p</E>
                                     values must be based on flow conditions at the beginning of the separation period and must be expressed at standard conditions or measured using a multiphase flow meter installed upstream of the separator capable of accurately measuring gas flow prior to separation.
                                </FP>
                                <FP SOURCE="FP-2">
                                    PR
                                    <E T="52">s,p</E>
                                     = Average gas production flow rate during the first 30-days of production after completions of newly drilled wells or well workovers using hydraulic fracturing, in standard cubic feet per hour of each well, p, that was measured in the sub-basin and well type combination. For oil wells for which production is not measured continuously during the first 30 days of production, the average flow rate may be based on individual well production tests conducted within the first 30 days of production. Alternatively, if applicable, PR
                                    <E T="52">s,p</E>
                                     may be calculated for oil wells using procedures specified in paragraph (g)(1)(vii) of this section.
                                </FP>
                                <FP SOURCE="FP-2">N = Number of measured or calculated well completions or workovers using hydraulic fracturing in a sub-basin and well type combination.</FP>
                            </EXTRACT>
                            <P>(v) For equation W-10A to this section, the ratio of gas flowback rate during well completions and workovers from hydraulic fracturing to 30-day gas production rate are applied to all well completions and well workovers, respectively, in the sub-basin and well type combination for the total number of hours of flowback and for the first 30 day average gas production rate for each of these wells.</P>
                            <P>(vi) For equations W-12A and W-12B to this section, calculate new flowback rates for well completions and well workovers in each sub-basin and well type combination once every two years starting in the first calendar year of data collection.</P>
                            <P>
                                (vii) For oil wells where the gas production rate is not metered and you elect to use equation W-10A to this section, calculate the average gas production rate (PR
                                <E T="52">s,p</E>
                                ) using equation W-12C to this section. If GOR cannot be determined from your available data, then you must use one of the procedures specified in paragraph (g)(1)(vii)(A) or (B) of this section to determine GOR. If GOR from each well is not available, use the GOR from a cluster of wells in the same sub-basin category.
                            </P>
                            <GPH SPAN="3" DEEP="30">
                                <GID>ER14MY24.064</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    PR
                                    <E T="52">s,p</E>
                                     = Average gas production flow rate during the first 30 days of production after completions of newly drilled wells or well workovers using hydraulic fracturing in standard cubic feet per hour of well p, in the sub-basin and well type combination.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GOR
                                    <E T="52">p</E>
                                     = Average gas to oil ratio during the first 30 days of production after completions of newly drilled wells or workovers using hydraulic fracturing in 
                                    <PRTPAGE P="42254"/>
                                    standard cubic feet of gas per barrel of oil for each well p, that was measured in the sub-basin and well type combination; oil here refers to hydrocarbon liquids produced of all API gravities.
                                </FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">p</E>
                                     = Volume of oil produced during the first 30 days of production after completions of newly drilled wells or well workovers using hydraulic fracturing in barrels of each well p, that was measured in the sub-basin and well type combination.
                                </FP>
                                <FP SOURCE="FP-2">720 = Conversion from 30 days of production to hourly production rate.</FP>
                            </EXTRACT>
                            <P>(A) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists.</P>
                            <P>(B) You may use an industry standard practice as described in § 98.234(b).</P>
                            <P>(2) For paragraphs (g) introductory text and (g)(1) of this section, measurements and calculations are completed separately for workovers and completions per sub-basin and well type combination. A well type combination is a unique combination of the parameters listed in paragraphs (g)(2)(i) through (iv) of this section.</P>
                            <P>(i) Vertical or horizontal (directional drilling).</P>
                            <P>(ii) With flaring or without flaring.</P>
                            <P>(iii) Reduced emission completion/workover or not reduced emission completion/workover.</P>
                            <P>(iv) Oil well or gas well.</P>
                            <P>
                                (3) Calculate both CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric and mass emissions from total natural gas volumetric emissions using calculations in paragraphs (u) and (v) of this section.
                            </P>
                            <P>
                                (h) 
                                <E T="03">Gas well venting during completions and workovers without hydraulic fracturing</E>
                                . Calculate annual volumetric natural gas emissions from each gas well venting during workovers without hydraulic fracturing using equation W-13A to this section. Calculate annual volumetric natural gas emissions from each gas well venting during completions without hydraulic fracturing using equation W-13B to this section. You must convert annual volumetric natural gas emissions to CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric and mass emissions as specified in paragraph (h)(1) of this section. If emissions from gas well venting during completions and workovers without hydraulic fracturing are routed to a flare, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O annual emissions as specified in paragraph (n) of this section, report emissions from the flare as specified in § 98.236(n), and report additional information specified in § 98.236(h), as applicable.
                            </P>
                            <GPH SPAN="3" DEEP="16">
                                <GID>ER14MY24.065</GID>
                            </GPH>
                            <GPH SPAN="3" DEEP="15">
                                <GID>ER14MY24.066</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,wo</E>
                                     = Annual volumetric natural gas emissions in standard cubic feet from gas well venting during well workovers without hydraulic fracturing.
                                </FP>
                                <FP SOURCE="FP-2">
                                    N
                                    <E T="52">wo</E>
                                     = Number of workovers per well that do not involve hydraulic fracturing in the reporting year.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">wo</E>
                                     = Emission factor for non-hydraulic fracture well workover venting in standard cubic feet per workover. Use 3,114 standard cubic feet natural gas per well workover without hydraulic fracturing.
                                </FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,p</E>
                                     = Annual volumetric natural gas emissions in standard cubic feet from gas well venting during well completions without hydraulic fracturing.
                                </FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">p</E>
                                     = Average daily gas production rate in standard cubic feet per hour for each well, p, undergoing completion without hydraulic fracturing. This is the total annual gas production volume divided by total number of hours the well produced to the flow-line. For completed wells that have not established a production rate, you may use the average flow rate from the first 30 days of production. In the event that the well is completed less than 30 days from the end of the calendar year, the first 30 days of the production straddling the current and following calendar years shall be used.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">p</E>
                                     = Time that gas is vented directly to the atmosphere for each well, p, undergoing completion without hydraulic fracturing, in hours during the year.
                                </FP>
                            </EXTRACT>
                            <P>
                                (1) Calculate both CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric emissions from natural gas volumetric emissions using calculations in paragraph (u) of this section. Calculate both CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions from volumetric emissions vented to atmosphere using calculations in paragraph (v) of this section.
                            </P>
                            <P>(2) [Reserved]</P>
                            <P>
                                (i) 
                                <E T="03">Blowdown vent stacks</E>
                                . Calculate CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 blowdown vent stack emissions from the depressurization of equipment to reduce system pressure for planned or emergency shutdowns resulting from human intervention or to take equipment out of service for maintenance as specified in either paragraph (i)(2) or (3) of this section. You may use the method in paragraph (i)(2) of this section for some blowdown vent stacks at your facility and the method in paragraph (i)(3) of this section for other blowdown vent stacks at your facility. For industry segments other than natural gas distribution, equipment with a unique physical volume of less than 50 cubic feet as determined in paragraph (i)(1) of this section are not subject to the requirements in paragraphs (i)(2) through (4) of this section. Natural gas distribution blowdowns with a unique physical volume of less than 500 cubic feet as determined in paragraph (i)(1) of this section are not subject to the requirements in paragraphs (i)(2) through (4) of this section. The requirements in this paragraph (i) do not apply to blowdown vent stack emissions from depressurizing to a flare, over-pressure relief, operating pressure control venting, blowdown of non-GHG gases, and desiccant dehydrator blowdown venting before reloading. If emissions from blowdown vent stacks are routed to a flare, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O annual emissions as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n).
                            </P>
                            <P>
                                (1) 
                                <E T="03">Method for calculating unique physical volumes or distribution pipeline physical volumes.</E>
                                 You must calculate each unique physical volume (including pipelines, compressor case or cylinders, manifolds, suction bottles, discharge bottles, and vessels) between isolation valves, in cubic feet, by using engineering estimates based on best available data. For natural gas distribution pipelines without isolation valves, calculate the unique physical volume of the distribution pipeline section that was isolated from operation by methods other than isolation valves, in cubic feet, by using engineering estimates based on best available data (e.g., diameter of the pipeline and length of isolated section).
                            </P>
                            <P>
                                (2) 
                                <E T="03">Method for determining emissions from blowdown vent stacks according to equipment or event type</E>
                                . If you elect to determine emissions according to each equipment or event type, using unique physical volumes as calculated in paragraph (i)(1) of this section, you must calculate emissions as specified in paragraph (i)(2)(i) of this section and either paragraph (i)(2)(ii) of this section or, if applicable, paragraph (i)(2)(iii) of 
                                <PRTPAGE P="42255"/>
                                this section for each equipment or event type. Categorize equipment and event types for each industry segment as specified in paragraph (i)(2)(iv) of this section.
                            </P>
                            <P>(i) Calculate the total annual natural gas emissions from each unique physical volume that is blown down using either equation W-14A or W-14B to this section.</P>
                            <GPH SPAN="3" DEEP="39">
                                <GID>ER14MY24.067</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,n</E>
                                     = Annual natural gas emissions at standard conditions from each unique physical volume that is blown down, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">N = Number of occurrences of blowdowns for each unique physical volume in the calendar year.</FP>
                                <FP SOURCE="FP-2">V = Unique physical volume, in cubic feet, as calculated in paragraph (i)(1) of this section.</FP>
                                <FP SOURCE="FP-2">C = Purge factor is 1 if the unique physical volume is not purged, or 0 if the unique physical volume is purged using non-GHG gases.</FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">s</E>
                                     = Temperature at standard conditions (60 °F).
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">a</E>
                                     = Temperature at actual conditions in the unique physical volume (°F). For emergency blowdowns at onshore petroleum and natural gas production, onshore petroleum and natural gas gathering and boosting facilities, onshore natural gas transmission pipeline facilities, and natural gas distribution facilities, engineering estimates based on best available information may be used to determine the temperature.
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">s</E>
                                     = Absolute pressure at standard conditions (14.7 psia).P
                                    <E T="52">a</E>
                                     = Absolute pressure at actual conditions in the unique physical volume (psia). For emergency blowdowns at onshore petroleum and natural gas production, onshore petroleum and natural gas gathering and boosting facilities, onshore natural gas transmission pipeline facilities, and natural gas distribution facilities, engineering estimates based on best available information may be used to determine the pressure.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Z
                                    <E T="52">a</E>
                                     = Compressibility factor at actual conditions for natural gas. You may use either a default compressibility factor of 1, or a site-specific compressibility factor based on actual temperature and pressure conditions.
                                </FP>
                            </EXTRACT>
                            <GPH SPAN="3" DEEP="39">
                                <GID>ER14MY24.068</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,n</E>
                                     = Annual natural gas emissions at standard conditions from each unique physical volume that is blown down, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">p = Individual occurrence of blowdown for the same unique physical volume.</FP>
                                <FP SOURCE="FP-2">N = Number of occurrences of blowdowns for each unique physical volume in the calendar year.</FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">p</E>
                                     = Unique physical volume, in cubic feet, for each blowdown “p.”
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">s</E>
                                     = Temperature at standard conditions (60 °F).T
                                    <E T="52">a,p</E>
                                     = Temperature at actual conditions in the unique physical volume (°F) for each blowdown “p”. For emergency blowdowns at onshore petroleum and natural gas production, onshore petroleum and natural gas gathering and boosting facilities, onshore natural gas transmission pipeline facilities, and natural gas distribution facilities, engineering estimates based on best available information may be used to determine the temperature.
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">s</E>
                                     = Absolute pressure at standard conditions (14.7 psia).
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">a,b,p</E>
                                     = Absolute pressure at actual conditions in the unique physical volume (psia) at the beginning of the blowdown “p”. For emergency blowdowns at onshore petroleum and natural gas production, onshore petroleum and natural gas gathering and boosting facilities, onshore natural gas transmission pipeline facilities, and natural gas distribution facilities, engineering estimates based on best available information may be used to determine the pressure at the beginning of the blowdown.
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">a,e,p</E>
                                     = Absolute pressure at actual conditions in the unique physical volume (psia) at the end of the blowdown “p”; 0 if blowdown volume is purged using non-GHG gases. For emergency blowdowns at onshore petroleum and natural gas production, onshore petroleum and natural gas gathering and boosting facilities, onshore natural gas transmission pipeline facilities, and natural gas distribution facilities, engineering estimates based on best available information may be used to determine the pressure at the end of the blowdown.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Z
                                    <E T="52">a</E>
                                     = Compressibility factor at actual conditions for natural gas. You may use either a default compressibility factor of 1, or a site-specific compressibility factor based on actual temperature and pressure conditions.
                                </FP>
                            </EXTRACT>
                            <P>
                                (ii) Except as allowed in paragraph (i)(2)(iii) of this section, calculate annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric and mass emissions from each unique physical volume that is blown down by using the annual natural gas emission value as calculated in either equation W-14A or equation W-14B to this section and the calculation method specified in paragraph (i)(4) of this section. Calculate the total annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions for each equipment or event type by summing the annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions for all unique physical volumes associated with the equipment or event type.
                            </P>
                            <P>
                                (iii) For onshore natural gas transmission compression facilities and LNG import and export equipment, as an alternative to using the procedures in paragraph (i)(2)(ii) of this section, you may elect to sum the annual natural gas emissions as calculated using either equation W-14A or equation W-14B to this section for all unique physical volumes associated with the equipment type or event type. Calculate the total annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric and mass emissions for each equipment type or event type using the sums of the total annual natural gas emissions for each equipment type and the calculation method specified in paragraph (i)(4) of this section.
                            </P>
                            <P>(iv) Categorize blowdown vent stack emission events as specified in paragraphs (i)(2)(iv)(A) and (B) of this section, as applicable.</P>
                            <P>
                                (A) For the onshore petroleum and natural gas production, onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, LNG import and export equipment, and onshore petroleum and natural gas gathering and boosting industry segments, equipment or event types must be grouped into the following seven categories: Facility piping (
                                <E T="03">i.e.,</E>
                                  
                                <PRTPAGE P="42256"/>
                                physical volumes associated with piping for which the entire physical volume is located within the facility boundary), pipeline venting (
                                <E T="03">i.e.,</E>
                                 physical volumes associated with pipelines for which a portion of the physical volume is located outside the facility boundary and the remainder, including the blowdown vent stack, is located within the facility boundary), compressors, scrubbers/strainers, pig launchers and receivers, emergency shutdowns (this category includes emergency shutdown blowdown emissions regardless of equipment type), and all other equipment with a physical volume greater than or equal to 50 cubic feet. If a blowdown event resulted in emissions from multiple equipment types and the emissions cannot be apportioned to the different equipment types, then categorize the blowdown event as the equipment type that represented the largest portion of the emissions for the blowdown event.
                            </P>
                            <P>
                                (B) For the onshore natural gas transmission pipeline and natural gas distribution industry segments, pipeline segments or event types must be grouped into the following eight categories: Pipeline integrity work (
                                <E T="03">e.g.,</E>
                                 the preparation work of modifying facilities, ongoing assessments, maintenance or mitigation), traditional operations or pipeline maintenance, equipment replacement or repair (
                                <E T="03">e.g.,</E>
                                 valves), pipe abandonment, new construction or modification of pipelines including commissioning and change of service, operational precaution during activities (
                                <E T="03">e.g.</E>
                                 excavation near pipelines), emergency shutdowns including pipeline incidents as defined in 49 CFR 191.3, and all other pipeline segments with a physical volume greater than or equal to 50 cubic feet. If a blowdown event resulted in emissions from multiple categories and the emissions cannot be apportioned to the different categories, then categorize the blowdown event in the category that represented the largest portion of the emissions for the blowdown event.
                            </P>
                            <P>
                                (3) 
                                <E T="03">Method for determining emissions from blowdown vent stacks using a flow meter.</E>
                                 In lieu of determining emissions from blowdown vent stacks as specified in paragraph (i)(2) of this section, you may use a flow meter and measure blowdown vent stack emissions for any unique physical volumes determined according to paragraph (i)(1) of this section to be greater than or equal to 50 cubic feet. If you choose to use this method, you must measure the natural gas emissions from the blowdown(s) through the monitored stack(s) using a flow meter according to methods in § 98.234(b) and calculate annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric and mass emissions measured by the meters according to paragraph (i)(4) of this section.
                            </P>
                            <P>
                                (4) 
                                <E T="03">Method for converting from natural gas emissions to GHG volumetric and mass emissions.</E>
                                 Calculate both CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric and mass emissions using the methods specified in paragraphs (u) and (v) of this section.
                            </P>
                            <P>
                                (j) 
                                <E T="03">Hydrocarbon liquids and produced water storage tanks.</E>
                                 Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from atmospheric pressure storage tanks receiving hydrocarbon liquids and CH
                                <E T="52">4</E>
                                 emissions from atmospheric pressure storage tanks receiving produced water, from onshore petroleum and natural gas production facilities, onshore petroleum and natural gas gathering and boosting facilities (including stationary liquid storage not owned or operated by the reporter), and onshore natural gas processing facilities as specified in this paragraph (j). For wells, gas-liquid separators, or onshore petroleum and natural gas gathering and boosting or onshore natural gas processing non-separator equipment (
                                <E T="03">e.g.,</E>
                                 stabilizers, slug catchers) with annual average daily throughput of hydrocarbon liquids greater than or equal to 10 barrels per day, calculate annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 using Calculation Method 1 or 2 as specified in paragraphs (j)(1) and (2) of this section. For wells, gas-liquid separators, or non-separator equipment with annual average daily throughput of hydrocarbon liquids greater than 0 barrels per day and less than 10 barrels per day, calculate annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions using Calculation Method 1, 2, or 3 as specified in paragraphs (j)(1) through (3) of this section. Annual average daily throughput of hydrocarbon liquids should be calculated using the flow out of the separator, well, or non-separator equipment determined over the actual days of operation. For atmospheric pressure storage tanks receiving produced water, calculate annual CH
                                <E T="52">4</E>
                                 emissions using Calculation Method 1, 2, or 3 as specified in paragraphs (j)(1) through (3) of this section. If you are required to use the flash emissions modeling software in paragraph (j)(1) of this section for compliance with federal or state regulations, air permit requirements, or annual inventory reporting for the current reporting year, you must use Calculation Method 1 to calculate annual CH
                                <E T="52">4</E>
                                 and, if applicable, CO
                                <E T="52">2</E>
                                 emissions. For atmospheric pressure storage tanks routing emissions to a vapor recovery system or a flare, calculate annual emissions vented directly to atmosphere as specified in paragraph (j)(4) of this section. If you use Calculation Method 1 or Calculation Method 2 for gas-liquid separators sending hydrocarbon liquids to atmospheric pressure storage tanks, you must also calculate emissions that may have occurred due to hydrocarbon liquid dump valves not closing properly using the method specified in paragraph (j)(5) of this section. If emissions from atmospheric pressure storage tanks are routed to a flare, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O emissions for the flare stack as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n).
                            </P>
                            <P>
                                (1) 
                                <E T="03">Calculation Method 1.</E>
                                 For atmospheric pressure storage tanks receiving hydrocarbon liquids, calculate annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions, and for atmospheric pressure tanks receiving produced water, calculate annual CH
                                <E T="52">4</E>
                                 emissions, using operating conditions in the well, last gas-liquid separator, or last non-separator equipment before liquid transfer to storage tanks. Calculate flashing emissions with a software program, such as AspenTech HYSYS®, Bryan Research &amp; Engineering ProMax®, or, for atmospheric pressure storage tanks receiving hydrocarbon liquids from gas-liquid separator or non-separator equipment, API 4697 E&amp;P Tank, that uses the Peng-Robinson equation of state, models flashing emissions, and speciates CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions that will result when the hydrocarbon liquids or produced water from the well, separator, or non-separator equipment enter an atmospheric pressure storage tank. If you elect to use ProMax®, you must use version 5.0 or above. A minimum of the parameters listed in paragraphs (j)(1)(i) through (vii) of this section, as applicable, must be used to characterize emissions. If paragraphs (j)(1)(i) through (vii) of this section indicate that an applicable parameter must be measured, collect measurements reflective of representative operating conditions for the time period covered by the simulation and at least at the frequency specified. Determine all other applicable parameters in paragraphs (j)(1)(i) through (vii) of this section by engineering estimate and process knowledge based on best available data and, if necessary, adjust parameters to represent the operating conditions over the time period covered by the simulation. Determine the number of simulations and associated time periods such that the simulations cover the entire reporting year (
                                <E T="03">i.e.,</E>
                                 if you calculate emissions using one simulation, use representative parameters for the operating conditions 
                                <PRTPAGE P="42257"/>
                                over the calendar year; if you use periodic simulations to cover the calendar year, use parameters for the operating conditions over each corresponding appropriate portion of the calendar year). If more than one simulation is performed, input parameters should be remeasured if no longer representative of operating conditions.
                            </P>
                            <P>(i) Well, separator, or non-separator equipment temperature (must be measured at least annually if required as an input for the model).</P>
                            <P>(ii) Well, separator, or non-separator equipment pressure (must be measured at least annually if required as an input for the model).</P>
                            <P>(iii) [Reserved]</P>
                            <P>(iv) Sales or stabilized hydrocarbon liquids or produced water production rate (must be measured at least annually if required as an input for the model).</P>
                            <P>(v) Ambient air temperature.</P>
                            <P>(vi) Ambient air pressure.</P>
                            <P>(vii) Sales or stabilized hydrocarbon liquids API gravity, and well, separator, or non-separator equipment hydrocarbon liquids or produced water composition and Reid vapor pressure (must be measured if required as an input for the model). Use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as specified in § 98.234(b) to sample and analyze sales or stabilized hydrocarbon liquids for API gravity, and hydrocarbon liquids or produced water composition and Reid vapor pressure. You must sample and analyze sales or stabilized oil for API gravity, and hydrocarbon liquids or produced water for composition and Reid vapor pressure within six months of equipment start-up or by January 1, 2030, whichever is later, and at least once every five years thereafter. Until such time that a sample is collected, determine API gravity by engineering estimate and process knowledge based on best available data, and determine composition and Reid vapor pressure by using one of the methods described in paragraphs (j)(1)(vii)(A) through (C) of this section. For produced water, you may instead elect to use a representative sales oil or stabilized hydrocarbon liquid API gravity and a hydrocarbon liquid composition and Reid vapor pressure, and assume oil entrainment of 1 percent or greater.</P>
                            <P>(A) If separator or non-separator equipment hydrocarbon liquids composition and Reid vapor pressure default data are provided with the software program, select the default values that most closely match your separator or non-separator equipment pressure first, and API gravity secondarily.</P>
                            <P>(B) If separator or non-separator equipment hydrocarbon liquids composition and Reid vapor pressure data are available through your previous analysis, select the latest available analysis that is representative of hydrocarbon liquids from the sub-basin category for onshore petroleum and natural gas production or from the county for onshore petroleum and natural gas gathering and boosting.</P>
                            <P>(C) Analyze a representative sample of separator or non-separator equipment hydrocarbon liquids in each sub-basin category for onshore petroleum and natural gas production or each county for onshore petroleum and natural gas gathering and boosting for hydrocarbon liquids composition and Reid vapor pressure using an appropriate standard method published by a consensus-based standards organization.</P>
                            <P>
                                (2) 
                                <E T="03">Calculation Method 2.</E>
                                 For atmospheric pressure storage tanks receiving hydrocarbon liquids, calculate annual CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions and for atmospheric pressure tanks receiving produced water, calculate annual CH
                                <E T="52">4</E>
                                 emissions, using operating conditions in the well, last gas-liquid separator, or last non-separator equipment before liquid transfer to storage tanks and the methods in paragraph (j)(2)(i) of this section.
                            </P>
                            <P>
                                (i) Assume that all of the CH
                                <E T="52">4</E>
                                 and, if applicable, CO
                                <E T="52">2</E>
                                 in solution at well, separator, or non-separator equipment temperature and pressure is emitted from hydrocarbon liquids or produced water sent to atmospheric pressure storage tanks. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as described in § 98.234(b) to sample and analyze hydrocarbon liquids or produced water composition at well, separator, or non-separator pressure and temperature. You must sample and analyze hydrocarbon liquids or produced water composition within six months of equipment start-up or by January 1, 2030, whichever is later, and at least once every five years thereafter. Until such time that a sample is collected, determine produced water composition by engineering estimate and process knowledge based on best available data, and determine hydrocarbon liquids composition by using one of the methods described in paragraphs (j)(1)(vii)(A) through (C) of this section. For produced water, you may instead elect to use a representative hydrocarbon liquid composition and assume oil entrainment of 1 percent or greater.
                            </P>
                            <P>(ii) [Reserved]</P>
                            <P>
                                (3) 
                                <E T="03">Calculation Method 3.</E>
                                 Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from atmospheric pressure storage tanks receiving hydrocarbon liquids as specified in paragraph (j)(3)(i) of this section. Calculate CH
                                <E T="52">4</E>
                                 emissions from atmospheric pressure storage tanks receiving produced water as specified in paragraph (j)(3)(ii) of this section.
                            </P>
                            <P>
                                (i) Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from atmospheric pressure storage tanks receiving hydrocarbon liquids using equation W-15A to this section:
                            </P>
                            <GPH SPAN="3" DEEP="14">
                                <GID>ER14MY24.069</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i</E>
                                     = Annual total volumetric GHG emissions (either CO
                                    <E T="52">2</E>
                                     or CH
                                    <E T="52">4</E>
                                    ) at standard conditions in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">i</E>
                                     = Population emission factor for separators, wells, or non-separator equipment in thousand standard cubic feet per separator, well, or non-separator equipment per year, for crude oil use 4.2 for CH
                                    <E T="52">4</E>
                                     and 2.8 for CO
                                    <E T="52">2</E>
                                     at 60 °F and 14.7 psia, and for gas condensate use 17.6 for CH
                                    <E T="52">4</E>
                                     and 2.8 for CO
                                    <E T="52">2</E>
                                     at 60 °F and 14.7 psia.
                                </FP>
                                <FP SOURCE="FP-2">Count = Total number of separators, wells, or non-separator equipment with annual average daily throughput greater than 0 barrels per day and less than 10 barrels per day. Count only separators, wells, or non-separator equipment that feed hydrocarbon liquids directly to the atmospheric pressure storage tank for which you elect to use this Calculation Method 3.</FP>
                                <FP SOURCE="FP-2">1,000 = Conversion from thousand standard cubic feet to standard cubic feet.</FP>
                            </EXTRACT>
                            <P>
                                (ii) Calculate CH
                                <E T="52">4</E>
                                 emissions from atmospheric pressure storage tanks receiving produced water using equation W-15B to this section:
                            </P>
                            <GPH SPAN="3" DEEP="14">
                                <PRTPAGE P="42258"/>
                                <GID>ER14MY24.070</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    Mass
                                    <E T="52">CH</E>
                                    <E T="0362">4</E>
                                     = Annual total CH
                                    <E T="52">4</E>
                                     emissions in metric tons.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">CH</E>
                                    <E T="0362">4</E>
                                     = Population emission factor for produced water in metric tons CH
                                    <E T="52">4</E>
                                     per thousand barrels produced water per year. For produced water streams from separators, wells, or non-separator equipment with pressure less than or equal to 50 psi, use 0.0015. For produced water streams from separators, wells, or non-separator equipment with pressure greater than 50 but less than or equal to 250 psi, use 0.0142. For produced water streams from separators, wells, or non-separator equipment with pressure greater than 250 psi, use 0.0508. Pressure should be representative of separators, wells, or non-separator equipment that feed produced water directly to the atmospheric pressure storage tank.
                                </FP>
                                <FP SOURCE="FP-2">FR = Annual flow rate of produced water to atmospheric pressure storage tanks, in barrels.</FP>
                                <FP SOURCE="FP-2">0.001 = Conversion from barrels to thousand barrels.</FP>
                            </EXTRACT>
                            <P>
                                (4) 
                                <E T="03">Emissions vented directly to atmosphere from atmospheric pressure storage tanks routed to vapor recovery systems or flares.</E>
                                 If the atmospheric pressure storage tank receiving your hydrocarbon liquids or produced water has a vapor recovery system or routes emissions to a flare, calculate annual emissions vented directly to atmosphere from the storage tank during periods of time when emissions were not routed to the vapor recovery system or flare as specified in paragraph (j)(4)(i) of this section. Determine recovered mass as specified in paragraph (j)(4)(ii) of this section.
                            </P>
                            <P>(i) For an atmospheric pressure storage tank that routes any emissions to a vapor recovery system or a flare, calculate vented emissions as specified in paragraphs (j)(4)(i)(A) through (E) of this section.</P>
                            <P>(A) Calculate vented emissions as specified in paragraph (j)(1), (2), or (3) of this section, which represents the emissions from the atmospheric storage tank prior to the vapor recovery system or flare. Calculate an average hourly vented emissions rate by dividing the vented emissions by the number of hours that the tank was in operation.</P>
                            <P>(B) To calculate vented emissions during periods when the tank was not routing emissions to a vapor recovery system or a flare, multiply the average hourly vented emissions rate determined in paragraph (j)(4)(i)(A) of this section by the number of hours that the tank vented directly to the atmosphere. Determine the number of hours that the tank vented directly to atmosphere by subtracting the hours that the tank was connected to a vapor recovery system or flare (based on engineering estimate and best available data) from the total operating hours for the tank in the calendar year. If emissions are routed to a flare but the flare is unlit, calculate emissions in accordance with the methodology specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n).</P>
                            <P>(C) During periods when a thief hatch is open and emissions from the tank are routed to a vapor recovery system or a flare, assume the capture efficiency of the vapor recovery system or a flare is 0 percent. A thief hatch is open if it is fully or partially open such there is a visible gap between the hatch cover and the hatch portal. To calculate vented emissions during such periods, multiply the average hourly vented emissions rate determined in paragraph (j)(4)(i)(A) of this section by the number of hours that the thief hatch is open. Determine the number of hours that the thief hatch is open or not properly seated as specified in paragraph (j)(7) of this section.</P>
                            <P>(D) Calculate vented emissions not captured by the vapor recovery system or a flare due to causes other than open thief hatches based on best available data, including any data from operating pressure sensors on atmospheric pressure storage tanks.</P>
                            <P>(E) Calculate total emissions vented directly to atmosphere as the sum of the emissions calculated as specified in paragraphs (j)(4)(i)(B) through (D) of this section.</P>
                            <P>
                                (ii) Using engineering estimates based on best available data, determine the portion of the total emissions estimated in paragraphs (j)(1) through (3) of this section that is recovered using a vapor recovery system. You must take into account periods with reduced capture efficiency of the vapor recovery system (
                                <E T="03">e.g.,</E>
                                 when a thief hatch is open) when calculating mass recovered as specified in paragraphs (j)(4)(i)(C) and (D) of this section.
                            </P>
                            <P>
                                (5) 
                                <E T="03">Gas-liquid separator dump valves</E>
                                . If you use Calculation Method 1 or Calculation Method 2 in paragraph (j)(1) or (2) of this section, calculate emissions from occurrences of gas-liquid separator liquid dump valves that did not close properly during the calendar year by using equation W-16 to this section. Determine the total time a dump valve did not close properly in the calendar year (Tdv) as specified in paragraph (j)(5)(i) of this section.
                            </P>
                            <GPH SPAN="3" DEEP="22">
                                <GID>ER14MY24.071</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,dv</E>
                                     = Annual volumetric GHG emissions (either CO
                                    <E T="52">2</E>
                                     or CH
                                    <E T="52">4</E>
                                    ) at standard conditions in cubic feet from atmospheric pressure storage tanks that resulted from the dump valve on an associated gas-liquid separator that did not close properly.
                                </FP>
                                <FP SOURCE="FP-2">
                                    CF
                                    <E T="52">dv</E>
                                     = Correction factor for tank emissions for time period T
                                    <E T="52">dv</E>
                                     is 2.87 for crude oil production. Correction factor for tank emissions for time period T
                                    <E T="52">dv</E>
                                     is 4.37 for gas condensate production.
                                </FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i</E>
                                     = Annual volumetric GHG emissions (either CO
                                    <E T="52">2</E>
                                     or CH
                                    <E T="52">4</E>
                                    ) as determined in paragraphs (j)(1) and (2) and, if applicable, (j)(4) of this section, in standard cubic feet per year, from atmospheric pressure storage tanks with dump valves on an associated gas-liquid separator that did not close properly.
                                </FP>
                                <FP SOURCE="FP-2">8,760 = Conversion to hourly emissions.</FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">dv</E>
                                     = Total time a dump valve did not close properly in the calendar year as determined in paragraph (j)(5)(i) of this section, in hours.
                                </FP>
                            </EXTRACT>
                            <P>
                                (i) If a parametric monitor is operating on a controlled atmospheric pressure storage tank or gas-liquid separator, you must use data obtained from the parametric monitor to determine periods when the gas-liquid separator liquid dump valve is stuck in an open or partially open position. An applicable operating parametric monitor must be capable of logging data whenever a gas-liquid separator liquid dump valve is stuck in an open or partially open position, as well as when the gas-liquid separator liquid dump valve is subsequently closed. If an applicable parametric monitor is not operating, including during periods of time when the parametric monitor is malfunctioning, you must perform a visual inspection of each gas-liquid separator liquid dump valve to determine if the valve is stuck in an 
                                <PRTPAGE P="42259"/>
                                open or partially open position, in accordance with paragraph (j)(5)(i)(A) and (B) of this section.
                            </P>
                            <P>(A) Audio, visual and olfactory inspections must be conducted at least once in a calendar year.</P>
                            <P>(B) If stuck gas-liquid separator liquid dump valve is identified, the dump valve must be counted as being open since the beginning of the calendar year, or from the previous audio, visual, and olfactory inspection that did not identify the dump valve as being stuck in the open position in the same calendar year. If the dump valve is fixed following visual inspection, the time period for which the dump valve was stuck open will end upon being repaired. If a stuck dump valve is identified and not repaired, the time period for which the dump valve was stuck open must be counted as having occurred through the rest of the calendar year.</P>
                            <P>(ii) [Reserved]</P>
                            <P>
                                (6) 
                                <E T="03">Mass emissions.</E>
                                 Calculate both CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions from natural gas volumetric emissions using calculations in paragraph (v) of this section.
                            </P>
                            <P>
                                (7) 
                                <E T="03">Thief hatches</E>
                                . If a thief hatch sensor is operating on a controlled atmospheric pressure storage tank, you must use data obtained from the thief hatch sensor to determine periods when the thief hatch is open. An applicable operating thief hatch sensor must be capable of logging data whenever a thief hatch is open, as well as when the thief hatch is subsequently closed. If a thief hatch sensor is not operating but a tank pressure sensor is operating on a controlled atmospheric pressure storage tank, you must use data obtained from the pressure sensor to determine periods when the thief hatch is open. An applicable operating pressure sensor must be capable of logging tank pressure data. If neither an applicable thief hatch sensor nor an applicable pressure sensor is operating, including during periods of time when the sensors are malfunctioning, for longer than 30 days, you must perform a visual inspection of each thief hatch on a controlled atmospheric pressure storage tank in accordance with paragraph (j)(7)(i) through (iii) of this section.
                            </P>
                            <P>(i) For thief hatches on controlled atmospheric pressure storage tanks subject to the standards in § 60.5395b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, visual inspections must be conducted at least as frequent as the required audio, visual, and olfactory inspections described in § 60.5416b or the applicable approved state plan or applicable Federal plan in part 62. If the time between required audio, visual, and olfactory inspections described in § 60.5416b or the applicable approved state plan or applicable Federal plan in part 62 is greater than one year, visual inspections must be conducted at least annually.</P>
                            <P>(ii) For thief hatches on controlled atmospheric pressure storage tanks not subject to the standards in § 60.5395b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, visual inspections must be conducted at least once in a calendar year.</P>
                            <P>(iii) If one visual inspection is conducted in the calendar year and an open thief hatch is found, assume the thief hatch was open for the entire calendar year or the entire period that the sensor(s) was not operating or malfunctioning. If multiple visual inspections are conducted in the calendar year, assume a thief hatch found open in the first visual inspection was open since the beginning of the year until the date of the visual inspection; assume a thief hatch found open in the last visual inspection of the year was open from the preceding visual inspection through the end of the year; assume a thief hatch found open in a visual inspection between the first and last visual inspections of the year was open since the preceding visual inspection until the date of the visual inspection.</P>
                            <P>
                                (k) 
                                <E T="03">Condensate storage tanks.</E>
                                 For vent stacks connected to one or more condensate storage tanks, either water or hydrocarbon, without vapor recovery, flares, or other controls, in onshore natural gas transmission compression or underground natural gas storage, calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 annual emissions from compressor scrubber dump valve leakage as specified in paragraphs (k)(1) through (4) of this section. If emissions from compressor scrubber dump valve leakage are routed to a flare, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O annual emissions as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n).
                            </P>
                            <P>(1) Except as specified in paragraph (k)(1)(iv) of this section, you must monitor the tank vapor vent stack annually for emissions using one of the methods specified in paragraphs (k)(1)(i) through (iii) of this section.</P>
                            <P>(i) Use an optical gas imaging instrument according to methods set forth in § 98.234(a)(1).</P>
                            <P>(ii) Measure the tank vent directly using a flow meter or high volume sampler according to methods in § 98.234(b) or (d) for a duration of 5 minutes.</P>
                            <P>(iii) Measure the tank vent using a calibrated bag according to methods in § 98.234(c) for a duration of 5 minutes or until the bag is full, whichever is shorter.</P>
                            <P>(iv) You may annually monitor leakage through compressor scrubber dump valve(s) into the tank using an acoustic leak detection device according to methods set forth in § 98.234(a)(5).</P>
                            <P>(2) If the tank vapors from the vent stack are continuous for 5 minutes, or the optical gas imaging instrument or acoustic leak detection device detects a leak, then you must use one of the methods in either paragraph (k)(2)(i) or (ii) of this section.</P>
                            <P>(i) Use a flow meter, such as a turbine meter, calibrated bag, or high volume sampler to estimate tank vapor volumes from the vent stack according to methods set forth in § 98.234(b) through (d). If you do not have a continuous flow measurement device, you may install a flow measuring device on the tank vapor vent stack. If the vent is directly measured for five minutes under paragraph (k)(1)(ii) or (iii) of this section to detect continuous leakage, this serves as the measurement.</P>
                            <P>(ii) Use an acoustic leak detection device on each scrubber dump valve connected to the tank according to the method set forth in § 98.234(a)(5).</P>
                            <P>(3) If a leaking dump valve is identified, the leak must be counted as having occurred since the beginning of the calendar year, or from the previous test that did not detect leaking in the same calendar year. If the leaking dump valve is fixed following leak detection, the leak duration will end upon being repaired. If a leaking dump valve is identified and not repaired, the leak must be counted as having occurred through the rest of the calendar year.</P>
                            <P>(4) Use the requirements specified in paragraphs (k)(4)(i) and (ii) of this section to quantify annual emissions.</P>
                            <P>(i) Use the appropriate gas composition in paragraph (u)(2)(iii) of this section.</P>
                            <P>
                                (ii) Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric and mass emissions at standard conditions using calculations in paragraphs (t), (u), and (v) of this section, as applicable to the monitoring equipment used.
                            </P>
                            <P>
                                (l) 
                                <E T="03">Well testing venting and flaring.</E>
                                 Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 annual emissions from well testing venting as specified in paragraphs (l)(1) through (5) of this section. If emissions from well testing venting are routed to a flare, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O annual emissions as specified in paragraph (n) of this section, report emissions from the flare as specified in § 98.236(n), and report additional 
                                <PRTPAGE P="42260"/>
                                information specified in § 98.236(l), as applicable.
                            </P>
                            <P>(1) Determine the gas to oil ratio (GOR) of the hydrocarbon production from oil well(s) tested. Determine the production rate from gas well(s) tested.</P>
                            <P>(2) If GOR cannot be determined from your available data, then you must measure quantities reported in this section according to one of the procedures specified in paragraph (l)(2)(i) or (ii) of this section to determine GOR.</P>
                            <P>(i) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists.</P>
                            <P>(ii) You may use an industry standard practice as described in § 98.234(b).</P>
                            <P>(3) Estimate venting emissions using equation W-17A to this section (for oil wells) or equation W-17B to this section (for gas wells) for each well tested during the reporting year.</P>
                            <GPH SPAN="3" DEEP="16">
                                <GID>ER14MY24.072</GID>
                            </GPH>
                            <GPH SPAN="3" DEEP="16">
                                <GID>ER14MY24.073</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">a,n</E>
                                     = Annual volumetric natural gas emissions from well testing for each well being tested in cubic feet under actual conditions.
                                </FP>
                                <FP SOURCE="FP-2">GOR = Gas to oil ratio in cubic feet of gas per barrel of oil for each well being tested; oil here refers to hydrocarbon liquids produced of all API gravities.</FP>
                                <FP SOURCE="FP-2">FR = Average annual flow rate in barrels of oil per day for the oil well being tested.</FP>
                                <FP SOURCE="FP-2">PR = Average annual production rate in actual cubic feet per day for the gas well being tested.</FP>
                                <FP SOURCE="FP-2">D = Number of days during the calendar year that the well is tested.</FP>
                            </EXTRACT>
                            <P>(4) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section.</P>
                            <P>
                                (5) Calculate both CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric and mass emissions from natural gas volumetric emissions using calculations in paragraphs (u) and (v) of this section.
                            </P>
                            <P>
                                (m) 
                                <E T="03">Associated gas venting and flaring.</E>
                                 Calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 annual emissions from associated gas venting not in conjunction with well testing (refer to paragraph (l) of this section) as specified in paragraphs (m)(1) through (3) of this section. If emissions from associated gas venting are routed to a flare, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O annual emissions as specified in paragraph (n) of this section, report emissions from the flare as specified in § 98.236(n), and report additional information specified in § 98.236(m), as applicable.
                            </P>
                            <P>(1) If you measure the gas flow to a vent using a continuous flow measurement device, you must use the measured flow volumes to calculate vented associated gas emissions.</P>
                            <P>(2) If you do not measure the gas flow to a vent using a continuous flow measurement device, you must follow the procedures in paragraphs (m)(2)(i) through (iii) of this section.</P>
                            <P>(i) Determine the GOR of the hydrocarbon production from each well whose associated natural gas is vented or flared. If GOR from each well is not available, use the GOR from a cluster of wells in the same sub-basin category.</P>
                            <P>(ii) If GOR cannot be determined from your available data, then you must use one of the procedures specified in paragraph (m)(2)(ii)(A) or (B) of this section to determine GOR.</P>
                            <P>(A) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists.</P>
                            <P>(B) You may use an industry standard practice as described in § 98.234(b).</P>
                            <P>(iii) Estimate venting emissions using equation W-18 to this section.</P>
                            <GPH SPAN="3" DEEP="16">
                                <GID>ER14MY24.074</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,n,p</E>
                                     = Annual volumetric natural gas emissions at each well from associated gas venting at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GOR
                                    <E T="52">p</E>
                                     = Gas to oil ratio, for well p, in standard cubic feet of gas per barrel of oil determined according to paragraphs (m)(2)(i) through (iii) of this section; oil here refers to hydrocarbon liquids produced of all API gravities.
                                </FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">p</E>
                                     = Volume of oil produced, for well p, in barrels in the calendar year only during time periods in which associated gas was vented or flared.
                                </FP>
                                <FP SOURCE="FP-2">
                                    SG
                                    <E T="52">p</E>
                                     = Volume of associated gas sent to sales and volume of associated gas used for other purposes at the facility site, including powering engines, separators, safety systems and/or combustion equipment and not flared or vented, for well p, in standard cubic feet of gas in the calendar year only during time periods in which associated gas was vented or flared.
                                </FP>
                            </EXTRACT>
                            <P>
                                (3) Calculate both CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraph (u) and (v) of this section.
                            </P>
                            <P>
                                (n) 
                                <E T="03">Flare stack emissions.</E>
                                 Except as specified in paragraph (n)(9) of this section, calculate CO
                                <E T="52">2</E>
                                , CH
                                <E T="52">4</E>
                                , and N
                                <E T="52">2</E>
                                O emissions from each flare stack as specified in paragraphs (n)(1) through (8) of this section. For each flare, disaggregate the total flared emissions to applicable source types as specified in paragraph (n)(10) of this section.
                            </P>
                            <P>
                                (1) 
                                <E T="03">Destruction efficiency and combustion efficiency.</E>
                                 To calculate CH
                                <E T="52">4</E>
                                 emissions for flares, use the applicable default destruction and combustion efficiencies specified in paragraphs (n)(1)(i) through (iii) of this section or alternative destruction and combustion efficiencies determined in accordance with paragraph (n)(1)(v) of this section. If you change the method with which you determine the default destruction and combustion efficiencies during a year, then use the applicable destruction and combustion efficiencies in paragraphs (n)(1)(i) through (iii) and paragraph (n)(1)(v) of this section for each portion of the year during which a different default destruction and combustion efficiency was used, and calculate an annual time-weighted average destruction and combustion efficiency to report for the flare.
                            </P>
                            <P>
                                (i) 
                                <E T="03">Tier 1</E>
                                . Use a default destruction efficiency of 98 percent and a default combustion efficiency of 96.5 percent if you follow the performance test requirements specified in paragraph 
                                <PRTPAGE P="42261"/>
                                (n)(1)(i)(A) of this section and the operating limit requirements specified in paragraph (n)(1)(i)(B) of this section, or the operating limit requirements specified in paragraph (n)(1)(i)(C) of this section, as applicable. You must also keep the applicable records in § 63.655(i)(2), (3), and (9) of this chapter. If you fail to fully conform with all cited provisions for a period of 15 consecutive days, you must utilize the Tier 3 default destruction and combustion efficiency values until such time that full conformance is achieved. You must document these periods and maintain records as specified in § 98.237 of the date when the non-conformance began, and the date when full conformance is re-established.
                            </P>
                            <P>
                                (A) The applicable testing requirements in § 63.645(a), (b), (c), (d), and (i) of this chapter, including § 63.116 (a)(2), (3), (b), and (c) of this chapter. When § 63.645 refers to “organic HAP,” the terms “methane” and “CO
                                <E T="52">2</E>
                                ” shall apply for the purposes of this subpart.
                            </P>
                            <P>(B) The applicable monitoring requirements in § 63.644(a), (b), (d), and (e) of this chapter. The data to submit in a Notification of Compliance Status report in § 63.644(d) of this chapter shall be maintained as records for the purposes of this section (n)(1)(i), and references to violations in § 63.644(e) of this chapter do not apply for the purposes of this section (n)(1)(i).</P>
                            <P>(C) The requirements in § 63.670 (a) through (n), § 63.670(p), and § 63.671 of this chapter.</P>
                            <P>
                                (ii) 
                                <E T="03">Tier 2</E>
                                . Use a default destruction efficiency of 95 percent and a default combustion efficiency of 93.5 percent if you follow the requirements specified in either paragraph (n)(1)(ii)(A), (B), (C), or (D) of this section. If you fail to fully conform with all cited provisions for a period of 15 consecutive days, you must utilize the Tier 3 default destruction and combustion efficiency values until such time that full conformance is achieved. You must document these periods and maintain records as specified in § 98.237 of the date when the non-conformance began, and the date when full conformance is re-established.
                            </P>
                            <P>(A) The requirements in § 60.5412b(a)(1) of this chapter, along with the applicable testing requirements in § 60.5413b of this chapter, the applicable continuous compliance requirements in § 60.5415b(f) of this chapter, and the applicable continuous monitoring requirements in § 60.5417b of this chapter. You must also keep the applicable records in § 60.5420b(c)(11) of this chapter.</P>
                            <P>(B) The requirements in § 60.5412b(a)(3) of this chapter, the applicable continuous compliance requirements in § 60.5415b(f) of this chapter, and the applicable continuous monitoring requirements in § 60.5417b(b) of this chapter. You must also keep the applicable records in § 60.5420b(c)(11) of this chapter.</P>
                            <P>(C) If using an enclosed combustion device tested by the manufacturer in accordance with § 60.5413b(d) of this chapter, the requirements in § 60.5413b(b)(5)(iii) and (e) of this chapter, the applicable continuous compliance requirements in § 60.5415b(f) of this chapter, and the applicable continuous monitoring requirements in § 60.5417b of this chapter. You must also keep the applicable records in § 60.5420b(c)(11) of this chapter.</P>
                            <P>(D) If you are subject to an approved state plan or applicable Federal plan in part 62 of this chapter that requires the reduction of methane by 95 percent, you may follow all applicable requirements of the approved state plan or applicable Federal plan in part 62 of this chapter, including the testing, continuous compliance, continuous monitoring, and recordkeeping requirements.</P>
                            <P>
                                (iii) 
                                <E T="03">Tier 3.</E>
                                 Use a default destruction efficiency of 92 percent and a default combustion efficiency of 90.5 percent if you do not meet the requirements specified in either paragraph (n)(1)(i) or (ii) of this section.
                            </P>
                            <P>
                                (iv) 
                                <E T="03">Alternative test method.</E>
                                 If you are utilizing the tier 2 default efficiencies in paragraph (n)(2)(ii) of this section and are not subject to 40 CFR subpart OOOOb or an applicable approved state or applicable federal plan under part 62 of this chapter that requires 95 percent reduction in methane emissions, you may conduct a performance test using EPA OTM-52 (incorporated by reference, see § 98.7) as an alternative to conducting a performance test using the methods specified in § 60.5413b of this chapter, or in an applicable approved state plan or applicable Federal plan in part 62 of this chapter. If the combustion efficiency obtained using OTM-52 is equal to or greater than 93.5 percent, then use a default destruction efficiency of 95 percent and a default combustion efficiency of 93.5 percent. If you utilize OTM-52 for the testing, you must comply with all the applicable monitoring, compliance, and recordkeeping requirements identified in paragraph (n)(1)(ii) of this section.
                            </P>
                            <P>
                                (v) 
                                <E T="03">Alternative destruction and combustion efficiencies.</E>
                                 You may use a directly measured combustion efficiency instead of the default combustion efficiencies specified in paragraphs (n)(1)(i) through (iii) of this section if you follow the provisions of paragraph (n)(1)(v)(A) through (E) of this section.
                            </P>
                            <P>(A) Measure the combustion efficiency in accordance with an alternative test method approved in accordance with § 60.5412b(d) of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter.</P>
                            <P>(B) Conduct monitoring as specified in §§ 60.5415b(f)(1)(x) and (xi) and 60.5417b(i) of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter.</P>
                            <P>(C) Adhere to all conditions in the monitoring plan you prepare as specified in § 60.5417b(i)(2) of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter at all times.</P>
                            <P>(D) You must use a destruction efficiency equal to the combustion efficiency plus 1.5.</P>
                            <P>(E) If you fail to fully conform with your plan for a period of 15 or more consecutive days, you must utilize the Tier 3 default destruction and combustion efficiency values until such time that full conformance is achieved. You must document these periods and maintain records as specified in § 98.237 of the date when the non-conformance began, and the date when full conformance is re-established.</P>
                            <P>
                                (2) 
                                <E T="03">Pilot</E>
                                . Continuously monitor for the presence of a pilot flame or combustion flame as specified in paragraph (n)(2)(i) of this section or visually inspect for the presence of a pilot flame or combustion flame as specified in paragraph (n)(2)(ii) of this section, as applicable.. If you comply with tier 2, you must also use data collected according to paragraph (n)(2)(iii) of this section in your calculations of time the flare was unlit and the fraction of gas routed to the flare during periods when the flare was unlit. If you continuously monitor, then periods when the flare is unlit must be determined based on those data, except when contradicted by data collected according to paragraph (n)(2)(iii) of this section. Determine the fraction of the total volume that is routed to the flare during unlit periods as specified in paragraph (n)(2)(iv) of this section.
                            </P>
                            <P>(i) At least once every five minutes monitor for the presence of a pilot flame or combustion flame using a device (including, but not limited to, a thermocouple, ultraviolet beam sensor, infrared sensor, video surveillance system, or advanced remote monitoring method) capable of detecting that the pilot or combustion flame is present at all times.</P>
                            <P>
                                (A) Monitoring for the presence of a flare flame in accordance with 
                                <PRTPAGE P="42262"/>
                                § 60.5417b satisfies the requirement of this paragraph (n)(2).
                            </P>
                            <P>(B) You may use multiple or redundant monitoring devices. When a discrepancy occurs between multiple devices, you must either visually confirm or use video surveillance output to confirm that the flame is present as soon as practicable after detecting the discrepancy to ensure that at least one device is operating properly. If you confirm that at least one device is operating properly, you may rely on the properly operating device(s) to monitor the flame.</P>
                            <P>(C) Continuous monitoring systems used for the presence of a pilot flame or combustion flame are not subject to a minimum accuracy requirement beyond being able to detect the presence or absence of a flame and are exempt from the calibration requirements of this part 98.</P>
                            <P>(D) Track the length of time over all periods when the flare is unlit and calculate the fraction of the total flow to the flare that was routed to the flare when the flare was unlit as specified in paragraph (n)(2)(iv) of this section.</P>
                            <P>(E) If all continuous monitoring devices are out of service for more than one week, then visually inspect for the presence of a pilot flame or combustion flame at least once per week for the first 4 weeks that the monitoring devices are out of service or until at least one repaired or new device is operational, whichever period is shorter. If all continuous monitoring devices are out of service for less than one week, then at least one visual inspection must be conducted during the outage. If a flame is not detected during a weekly visual inspection, assume the pilot has been unlit since the previous inspection or the last time the continuous monitoring device detected a flame, and assume that the pilot remains unlit until a subsequent inspection or continuous monitoring device detects a flame. If the monitoring device outage lasts more than 4 weeks, then you may switch to conducting inspections at least once per month in accordance with paragraph (n)(2)(ii) of this section.</P>
                            <P>(ii) As an alternative to continuous monitoring as specified in paragraph (n)(2)(i) of this section, if you comply with tier 3 in paragraph (n)(1)(iii) of this section, at least once per month visually inspect for the presence of a pilot flame or combustion flame. You may also conduct visual inspections when using an alternative test method in accordance with paragraph (n)(1)(iv) of this section that allows visual inspections. If a flame is not detected, track the time since the previous inspection until a subsequent inspection detects a flame, and use this time in your calculation of the fraction of the total flow to the flare that was routed to the flare when the flare was unlit as specified in paragraph (n)(2)(iv) of this section. Use the sum of the measured flows, as determined from measurements obtained under paragraph (n)(1) of this section, during all time periods when the pilot was determined to be unlit, to calculate the fraction of the total annual volume that is routed to the flare when it is unlit.</P>
                            <P>(iii) For a flare subject to 40 CFR part 60 subpart OOOOb, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, a flare inspection conducted using an OGI camera during a fugitive emissions survey in accordance with § 60.5415b(f)(1)(x) constitutes a pilot flame inspection under this subpart. If a flame is not detected, track the time from the previous inspection until a subsequent inspection or continuous monitoring device detects a flame and use this time in your calculation of the fraction of the total flow to the flare that was routed to the flare when the flare was unlit as specified in paragraph (n)(2)(iv) of this section.</P>
                            <P>(iv) If you measure total flow to the flare in accordance with paragraph (n)(3)(i) of this section, calculate the fraction of the total annual volume that is routed to the flare when it is unlit using the actual flow during the unlit time periods that are tracked according to paragraph (n)(2)(i)(D), (ii), or (iii) of this section. If you determine flows of individual streams routed to the flare in accordance with paragraph (n)(3)(ii) of this section, use the stream-specific average flow rates for the streams routed to the flare during unlit times to calculate the fraction of the total annual volume that is routed to the flare when it is unlit.</P>
                            <P>
                                (3) 
                                <E T="03">Flow determination.</E>
                                 Calculate total flow to the flare as specified in paragraph (n)(3)(i) of this section or determine flow of each individual stream that is routed to the flare as specified in paragraph (n)(3)(ii) of this section. Use engineering calculations based on best available data and company records to calculate pilot gas flow to add to the total gas flow to the flare.
                            </P>
                            <P>(i) Use a continuous parameter monitoring system to measure flow of gas to the flare downstream of any sweep, purge, or auxiliary gas addition. You may use either flow meters or indirectly calculate flow using other parameter monitoring systems combined with engineering calculations, such as line pressure, line size, and burner nozzle dimensions. If you use a continuous parameter monitoring system, you must use the measured flow in calculating the total flow volume to the flare. The continuous parameter monitoring system must measure data values at least once every hour.</P>
                            <P>(ii) Determine flow to the flare from individual sources, including sweep, purge, auxiliary fuel, and collective flow from offsite sources that route gas to the flare using any combination of the methods in paragraphs (n)(3)(ii)(A) and (B) of this section, as applicable. Adjust the volumes determined as specified in paragraphs (n)(3)(ii)(A) and (B) of this section by any estimated bypass volumes diverted from entering the flare and leaks from the closed vent system in accordance with paragraphs (n)(3)(ii)(C) and (D) of this section. Do not adjust the volumes routed to the flare for volumes diverted through bypass lines located upstream of the flow measurement or determination location.</P>
                            <P>(A) Use a continuous flow meter to measure the flow of gas from individual sources (or combination of sources) that route gas to the flare. If the emission streams for multiple sources are routed to a manifold before being combined with other emission streams, you may conduct the measurement in the manifold instead of from each source that is routed to the manifold. If you use a continuous flow meter, you must use the measured flow in calculating the total flow volume to the flare. The continuous flow meter must measure data values at least once every hour.</P>
                            <P>
                                (B) If flow from a source is not measured using a continuous flow meter, then use methods specified in paragraphs (n)(3)(ii)(B)(1) through (
                                <E T="03">8</E>
                                ) of this section, as applicable.
                            </P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) Determine flow of emission streams routed to flares from acid gas removal units using Calculation Method 3 or Calculation Method 4 as specified in paragraph (d)(3) or (4) of this section. Use the method specified in paragraph (n)(3)(ii)(B)(
                                <E T="03">8</E>
                                ) of this section to determine the volume of non-GHG constituents in a stream from an acid gas removal unit or nitrogen removal unit and add to the volume of GHGs to determine the total volume to the flare.
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) Determine flow of emission streams routed to flares from dehydrators using an applicable method specified in paragraph (e) of this section. When using Calculation Method 2 to determine volume of GHGs from small glycol dehydrators, also use the method specified in paragraph (n)(3)(ii)(B)(
                                <E T="03">8</E>
                                ) of this section to determine the volume of non-GHG constituents in the stream to the flare 
                                <PRTPAGE P="42263"/>
                                and add to the volume of GHGs to determine the total volume to the flare.
                            </P>
                            <P>
                                (
                                <E T="03">3</E>
                                ) Determine flow of emission streams routed to flares from completions and workovers with hydraulic fracturing using a method specified in paragraph (g) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">4</E>
                                ) Determine flow of emission streams routed to flares from completions and workovers without hydraulic fracturing using a method specified in paragraph (h) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">5</E>
                                ) Determine flow of emission streams routed to flares from hydrocarbon liquids and produced water storage tanks using a method specified in paragraph (j) of this section. When using Calculation Method 2 or Calculation Method 3 to calculate the volume of GHGs, use the method specified in paragraph (n)(3)(ii)(B)(
                                <E T="03">8</E>
                                ) of this section to determine the volume of non-GHG constituents in the stream to the flare and add to the volume of GHGs to determine the total volume to the flare.
                            </P>
                            <P>
                                (
                                <E T="03">6</E>
                                ) Determine flow of emission streams routed to flares from well testing using an applicable method specified in paragraph (l) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">7</E>
                                ) Determine flow of associated gas emission streams routed to flares using the method specified in paragraph (m)(2) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">8</E>
                                ) Use engineering calculations based on process knowledge, company records, and best available data to calculate flow for sources other than those described in paragraphs (n)(3)(ii)(B)(1) through (7) of this section and to calculate volume of non-GHG constituents in streams for which the method used in paragraphs (n)(3)(ii)(B)(
                                <E T="03">1</E>
                                ), (
                                <E T="03">2</E>
                                ), and (5) of this section calculates only the GHG flow.
                            </P>
                            <P>(C) If the closed vent system that routes emissions to the flare contains one or more bypass devices that could be used to divert all or a portion of the gases from entering the flare, then you must determine when flow is diverted through the bypass and estimate the volume that bypasses the flare. The bypass volume may be determined based on engineering calculations, process knowledge, and best available data. Use the estimated bypass volume to adjust the volumes determined in accordance with paragraph (n)(3)(ii)(A) or (B) of this section to determine the flow to the flare. For bypass volumes that are diverted directly to atmosphere, use the estimated volume in the calculation and reporting of vented emissions from the applicable source(s).</P>
                            <P>(D) If you determine a component in the closed vent system is leaking, you must adjust the flow determined in accordance with paragraph (n)(3)(ii)(A) or (B) of this section by the estimated volume of the leak to determine the flow to the flare. Estimate the leak volume based on engineering calculations, process knowledge, and best available data. Report the estimated leak volume as vented emissions from the applicable source(s).</P>
                            <P>
                                (4) 
                                <E T="03">Gas composition.</E>
                                 Determine the composition of the inlet gas to the flare as specified in either paragraph (n)(4)(i) or (ii) of this section, or determine composition of the individual streams that are combined and routed to the flare as specified in paragraph (n)(4)(iii) of this section. Use representative compositions of pilot gas determined by engineering calculation based on process knowledge and best available data.
                            </P>
                            <P>
                                (i) Use a continuous gas composition analyzer on the inlet gas to the flare burner downstream of any purge, sweep, or auxiliary fuel addition to measure annual average mole fractions of methane, ethane, propane, butane, pentanes plus, and CO
                                <E T="52">2</E>
                                . If you use a continuous gas composition analyzer on the total inlet stream to the flare, you must use the measured annual average mole fractions to calculate total emissions from the flare. The continuous gas composition analyzer must measure data values at least once every hour.
                            </P>
                            <P>
                                (ii) Take samples of the inlet gas to the flare burner downstream of any purge, sweep, or auxiliary fuel addition at least annually in which gas is routed to the flare and analyze for methane, ethane, propane, butane, pentanes plus, and CO
                                <E T="52">2</E>
                                 constituents. Determine the annual average concentration of each constituent as the annual average of all valid measurements for that constituent during the year and you must use those data to calculate flared emissions.
                            </P>
                            <P>(iii) When composition is not determined at the inlet to the flare as specified in either paragraph (i) or (ii) of this section, then determine annual average compositions for streams from individual sources (or combinations of sources), including sweep, purge, and auxiliary fuel, routed to the flare using any combination of the methods specified in paragraphs (n)(4)(iii)(A) and (B) of this section, as applicable.</P>
                            <P>
                                (A) Use a continuous gas composition analyzer to measure annual average mole fractions of methane, ethane, propane, butane, pentanes plus, and CO
                                <E T="52">2</E>
                                 constituents. If emission streams for multiple sources are routed to a manifold before being combined with other emission streams, you may measure gas composition in the manifold instead of from each source that is routed to the manifold. If you use a continuous gas composition analyzer, you must use the measured annual average mole fractions to calculate flared emissions for the stream. The continuous gas composition analyzer must measure data values at least once every hour.
                            </P>
                            <P>
                                (B) If composition is not measured in accordance with paragraph (n)(4)(iii)(A) of this section, then use methods specified in paragraphs (n)(4)(iii)(B)(
                                <E T="03">1</E>
                                ) through (
                                <E T="03">7</E>
                                ) of this section to determine composition, as applicable. When paragraphs (n)(4)(iii)(B)(
                                <E T="03">1</E>
                                ) through (
                                <E T="03">5</E>
                                ) reference continuous gas composition analyzer requirements in paragraph (u)(2) of this section, the requirements in paragraph (n)(4)(iii)(A) apply for the purposes of this paragraph (n)(4)(iii)(B). When paragraphs (n)(4)(iii)(B)(
                                <E T="03">1</E>
                                ) through (
                                <E T="03">5</E>
                                ) reference paragraph (u)(2) of this section, the language “your most recent available analysis” in paragraph (u)(2)(i) of this section means “annual samples” for the purposes of this paragraph (n)(4)(iii)(B).
                            </P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) Determine the total annual average GHG composition of streams from acid gas removal units based on either process simulation as specified in paragraph (d)(4) of this section or quarterly sampling in accordance with paragraphs (d)(6) and (10) of this section, and determine the composition of ethane, propane, butane, and pentanes plus as specified in paragraph (n)(4)(iii)(B)(5) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) Determine the total annual average composition of streams from glycol dehydrators using Calculation Method 1 as specified in paragraph (e)(1) of this section or determine the annual average GHG composition as specified in paragraph (u)(2) of this section for the applicable industry segment. Determine annual average GHG composition of streams from desiccant dehydrators as specified in paragraph (u)(2) of this section. If you determine GHG composition in accordance with paragraph (u)(2) of this section, also determine the composition of ethane, propane, butane, and pentanes plus as specified in paragraph (n)(4)(iii)(B)(
                                <E T="03">5</E>
                                ) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">3</E>
                                ) Determine the total annual average composition of streams from hydrocarbon liquids and produced water storage tanks using Calculation Method 1 in accordance with paragraph (j)(1) of this section or determine the annual average GHG composition as specified in paragraph (u)(2)(i) of this section. If you determine annual average GHG composition as specified in paragraph (u)(2)(i) of this section, then also determine the composition of 
                                <PRTPAGE P="42264"/>
                                ethane, propane, butane, and pentanes plus as specified in paragraph (n)(4)(iii)(B)(
                                <E T="03">5</E>
                                ) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">4</E>
                                ) For onshore natural gas processing facilities, determine GHG mole fractions for all emission sources downstream of the de-methanizer overhead or dew point control based on samples of facility-specific residue gas to transmission pipeline systems taken at least once per year according to methods set forth in § 98.234(b), and determine GHG mole fractions for all emission sources upstream of the de-methanizer or dew point control based on samples of feed natural gas taken at least once per year according to methods set forth in § 98.234(b). For onshore natural gas processing plants that solely fractionate a liquid stream, use the GHG mole fraction in feed natural gas liquid streams as determined from samples taken at least once per year. If multiple samples of a stream are taken in a year, use the arithmetic average GHG composition.
                            </P>
                            <P>
                                (
                                <E T="03">5</E>
                                ) Except as specified in paragraph (n)(4)(iii)(B)(
                                <E T="03">6</E>
                                ) of this section, for streams from any source type other than those identified in paragraphs (n)(4)(iii)(B)(
                                <E T="03">1</E>
                                ) through (
                                <E T="03">4</E>
                                ) of this section, and for purge gas, sweep gas, and auxiliary fuel, determine the annual average GHG composition as specified in paragraph (u)(2) of this section for the applicable industry segment, and determine the composition of ethane, propane, butane, and pentanes plus as specified in paragraph (n)(4)(iii)(B)(
                                <E T="03">7</E>
                                ) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">6</E>
                                ) When the stream going to the flare is a hydrocarbon product stream, such as methane, ethane, propane, butane, pentanes-plus, or mixed light hydrocarbons, you may use a representative composition from the source for the stream determined by engineering calculation based on process knowledge and best available data.
                            </P>
                            <P>
                                (
                                <E T="03">7</E>
                                ) When only the GHG composition is determined in accordance with paragraph (u)(2) of this section, determine the annual average composition of ethane, propane, butane, and pentanes plus in the stream using a representative composition based on process knowledge and best available data.
                            </P>
                            <P>
                                (5) 
                                <E T="03">Calculate CH</E>
                                <E T="54">4</E>
                                  
                                <E T="03">and CO</E>
                                <E T="54">2</E>
                                  
                                <E T="03">emissions</E>
                                . Calculate GHG volumetric emissions from flaring at standard conditions using equations W-19 and W-20 to this section and as specified in paragraphs (n)(5)(i) through (iv) of this section.
                            </P>
                            <GPH SPAN="3" DEEP="19">
                                <GID>ER14MY24.075</GID>
                            </GPH>
                            <GPH SPAN="3" DEEP="42">
                                <GID>ER14MY24.076</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,CH</E>
                                    <E T="0362">4</E>
                                     = Annual CH
                                    <E T="52">4</E>
                                     emissions from flare stack in cubic feet, at standard conditions.
                                </FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,CO</E>
                                    <E T="0362">2</E>
                                     = Annual CO
                                    <E T="52">2</E>
                                     emissions from flare stack in cubic feet, at standard conditions.
                                </FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">s</E>
                                     = Volume of gas sent to flare in standard cubic feet, during the year as determined in paragraph (n)(3) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    ηD = Flare destruction efficiency, expressed as fraction of hydrocarbon compounds in gas that is destroyed by a burning flare, but may or may not be completely oxidized to CO
                                    <E T="52">2</E>
                                    .
                                </FP>
                                <FP SOURCE="FP-2">
                                    ηC = Flare combustion efficiency, expressed as fraction of hydrocarbon compounds in gas that is oxidized to CO
                                    <E T="52">2</E>
                                     by a burning flare.
                                </FP>
                                <FP SOURCE="FP-2">
                                    X
                                    <E T="52">CH</E>
                                    <E T="0362">4</E>
                                     = Annual average mole fraction of CH
                                    <E T="52">4</E>
                                     in the feed gas to the flare or in each of the streams routed to the flare as determined in paragraph (n)(4) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    X
                                    <E T="52">CO</E>
                                    <E T="0362">2</E>
                                     = Annual average mole fraction of CO
                                    <E T="52">2</E>
                                     in the feed gas to the flare or in each of the streams routed to the flare as determined in paragraph (n)(4) of this section.
                                </FP>
                                <FP SOURCE="FP-2">ZU = Fraction of the feed gas sent to an un-lit flare determined from both the total time the flare was unlit as determined by monitoring the pilot flame or combustion flame as specified in paragraph (n)(2) of this section and the volume of gas routed to the flare during periods when the flare was unlit based on the flow determined in accordance with paragraph (n)(3) of this section.</FP>
                                <FP SOURCE="FP-2">
                                    Z
                                    <E T="52">L</E>
                                     = Fraction of the feed gas sent to a burning flare (equal to 1—ZU).
                                </FP>
                                <FP SOURCE="FP-2">
                                    Y
                                    <E T="52">j</E>
                                     = Annual average mole fraction of hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes-plus) in the feed gas to the flare or in each of the streams routed to the flare as determined in paragraph (n)(4) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    R
                                    <E T="52">j</E>
                                     = Number of carbon atoms in the hydrocarbon constituent j in the feed gas to the flare: 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes-plus).
                                </FP>
                            </EXTRACT>
                            <P>(i) If you measure the gas flow at the flare inlet as specified in paragraph (n)(3)(i) of this section and you measure gas composition for the inlet gas to the flare as specified in paragraph (n)(4)(i) or (ii) of this section, then use those data in equations W-19 and W-20 to this section to calculate total emissions from the flare.</P>
                            <P>(ii) If you determine the flow from each source as specified in paragraph (n)(3)(ii) of this section and you measure gas composition for the inlet gas to the flare as specified in paragraph (n)(4)(i) or (ii) of this section, then sum the flows for each stream to calculate the total annual gas flow to the flare. Use that total annual flow with the annual average concentration of each constituent as calculated in paragraph (n)(4)(i) or (ii) of this section in equations W-19 and W-20 to this section to calculate total emissions from the flare.</P>
                            <P>(iii) If you determine the flow from each source as specified in paragraph (n)(3)(ii) of this section and you determine gas composition for the emission stream from each source as specified in paragraph (n)(4)(iii) of this section, then calculate total emissions from the flare as specified in either paragraph (n)(5)(iii)(A) or (B) of this section.</P>
                            <P>(A) Use each set of stream-specific flow and annual average concentration data in equations W-19 and W-20 to this section to calculate stream-specific flared emissions for each stream, and then sum the results from each stream-specific calculation to calculate the total emissions from the flare.</P>
                            <P>
                                (B) Sum the flows from each source to calculate the total gas flow into the flare and use the source-specific flows and source-specific annual average concentrations to determine flow-weighted annual average concentrations of CO
                                <E T="52">2</E>
                                 and hydrocarbon constituents in the combined gas stream into the flare. Use the calculated total gas flow and the calculated flow-weighted annual average concentrations for the inlet gas stream to the flare in equations W-19 and W-20 to this section to calculate the total emissions from the flare.
                                <PRTPAGE P="42265"/>
                            </P>
                            <P>(iv) You may not combine measurement of the inlet gas flow to the flare as specified in paragraph (n)(3)(i) of this section with measurement of the gas composition of the streams from each source as specified in paragraph (n)(4)(iii) of this section.</P>
                            <P>
                                (6) 
                                <E T="03">Convert volume at actual conditions to volume at standard conditions.</E>
                                 Convert GHG volumetric emissions to standard conditions using calculations in paragraph (t) of this section.
                            </P>
                            <P>
                                (7) 
                                <E T="03">Convert volumetric emissions to mass emissions</E>
                                . Calculate both CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions from volumetric emissions using calculation in paragraph (v) of this section.
                            </P>
                            <P>
                                (8) 
                                <E T="03">Calculate N</E>
                                <E T="54">2</E>
                                <E T="03">O emissions.</E>
                                 Calculate N
                                <E T="52">2</E>
                                O emissions from flare stacks using equation W-40 to this section. Determine the values of parameters “HHV” and “Fuel” in equation W-40 to this section as specified in paragraphs (n)(8)(i) through (iv) of this section, as applicable.
                            </P>
                            <P>
                                (i) Directly measure the annual average higher heating value in the inlet stream to the flare using either a continuous gas composition analyzer or a calorimeter. Use this flare-specific annual average higher heating value for the parameter “HHV” in equation W-40 to this section, and use either the total inlet flow to the flare measured as specified in paragraph (n)(3)(i) of this section or the sum of the flows of individual streams routed to the flare as determined in paragraph (n)(3)(ii) of this section for the parameter “Fuel” in equation W-40 to this section to calculate the total N
                                <E T="52">2</E>
                                O emissions from the flare.
                            </P>
                            <P>
                                (ii) Calculate the annual average higher heating value in the inlet stream to the flare using annual average gas compositions of the inlet stream measured in accordance with paragraph (n)(4)(i) or (ii) of this section. Use this flare-specific annual average higher heating value for the parameter “HHV” in equation W-40 to this section, and use either the total inlet flow to the flare measured as specified in paragraph (n)(3)(i) of this section or the sum of the flows of individual streams routed to the flare as determined in paragraph (n)(3)(ii) of this section for the parameter “Fuel” in equation W-40 to this section to calculate the total N
                                <E T="52">2</E>
                                O emissions from the flare.
                            </P>
                            <P>
                                (iii) Directly measure the annual average higher heating values in the individual streams routed to the flare using either a continuous gas composition analyzer or a calorimeter. Calculate the total N
                                <E T="52">2</E>
                                O emissions from the flare as specified in either paragraph (n)(8)(iii)(A) or (B) of this section.
                            </P>
                            <P>
                                (A) Use the stream-specific annual average higher heating values for the parameter “HHV” in equation W-40 to this section, use the stream-specific flows as determined in paragraph (n)(3)(ii) of this section for the parameter “Fuel” in equation W-40 to this section in separate stream-specific calculations of N
                                <E T="52">2</E>
                                O emissions using equation W-40 to this section, and sum the resulting values to calculate the total N
                                <E T="52">2</E>
                                O emissions from the flare.
                            </P>
                            <P>
                                (B) Use the stream-specific annual average higher heating values and flows to calculate a flow-weighted annual average higher heating value to use as the parameter “HHV” in equation W-40 to this section and the sum of the individual stream flows routed to the flare as determined in paragraph (n)(3)(ii) of this section for the parameter “Fuel” in equation W-40 to this section to calculate total N
                                <E T="52">2</E>
                                O emissions from the flare.
                            </P>
                            <P>
                                (iv) Calculate annual average higher heating values for the individual streams routed to the flare using gas compositions determined in accordance with paragraph (n)(4)(iii) of this section. Calculate the total N
                                <E T="52">2</E>
                                O emissions from the flare as specified in either paragraph (n)(8)(iv)(A) or (B) of this section.
                            </P>
                            <P>
                                (A) Use the stream-specific annual average higher heating values and the stream-specific flows in separate stream-specific calculations of N
                                <E T="52">2</E>
                                O emissions using equation W-40 to this section and sum the resulting values to calculate the total N
                                <E T="52">2</E>
                                O emissions from the flare.
                            </P>
                            <P>
                                (B) Use the stream-specific annual average higher heating values and flows to calculate a flow-weighted annual average higher heating value to use as the parameter “HHV” in equation W-40 to this section and the sum of the individual stream flows routed to the flare as determined in paragraph (n)(3)(ii) of this section for the parameter “Fuel” in equation W-40 to this section to calculate total N
                                <E T="52">2</E>
                                O emissions from the flare.
                            </P>
                            <P>
                                (9) 
                                <E T="03">CEMS.</E>
                                 If you operate and maintain a CEMS that has both a CO
                                <E T="52">2</E>
                                 concentration monitor and volumetric flow rate monitor for the combustion gases from the flare, you must calculate CO
                                <E T="52">2</E>
                                 emissions for the flare using the CEMS. You must follow the Tier 4 Calculation Method and all associated calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). If a CEMS is used to calculate flare stack CO
                                <E T="52">2</E>
                                 emissions, you must also comply with all other requirements specified in paragraphs (n)(1) through (8) of this section, except that calculation of CO
                                <E T="52">2</E>
                                 emissions using equation W-20 to this section is not required.
                            </P>
                            <P>
                                (10) 
                                <E T="03">Disaggregation.</E>
                                 Disaggregate the total emissions from the flare as calculated in paragraphs (n)(7) and (8) of this section or paragraph (n)(9) of this section, as applicable, to each source type listed in paragraphs (n)(10)(i) through (viii) of this section, as applicable to the industry segment, that routed emissions to the flare. If emissions from the flare are calculated in accordance with paragraph (n)(5)(iii) of this section using stream-specific flow and composition, including combined streams that contain emissions from only a single source type, use the source-specific emissions calculated using these data to calculate the disaggregated emissions per source type. If the total emissions from the flare are calculated using total flow and/or total annual average composition of the total inlet stream to the flare, or if flow or composition are determined for a combined stream that contains emissions from more than one source type, then use engineering calculations and best available data to disaggregate the total emissions to the applicable source types.
                            </P>
                            <P>(i) Acid gas removal units.</P>
                            <P>(ii) Dehydrators.</P>
                            <P>(iii) Completions and workovers with hydraulic fracturing.</P>
                            <P>(iv) Completions and workovers without hydraulic fracturing.</P>
                            <P>(v) Hydrocarbon liquids and produced water storage tanks.</P>
                            <P>(vi) Well testing.</P>
                            <P>(vii) Associated gas.</P>
                            <P>(viii) Other (collectively).</P>
                            <P>
                                (o) 
                                <E T="03">Centrifugal compressor venting.</E>
                                 If you are required to report emissions from centrifugal compressor venting as specified in § 98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), you must conduct volumetric emission measurements specified in paragraph (o)(1) of this section using methods specified in paragraphs (o)(2) through (5) of this section; perform calculations specified in paragraphs (o)(6) through (9) of this section; and calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions as specified in paragraph (o)(11) of this section. If you are required to report emissions from centrifugal compressor venting at an onshore petroleum and natural gas production facility as specified in § 98.232(c)(19) or an onshore petroleum and natural gas gathering and boosting facility as specified in § 98.232(j)(8), you must calculate volumetric emissions as specified in paragraph (o)(10) of this section and calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions as specified in paragraph (o)(11) of this section. If emissions from a compressor source are routed to a 
                                <PRTPAGE P="42266"/>
                                flare, paragraphs (o)(1) through (11) of this section do not apply and instead you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O emissions as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n). If emissions from a compressor source are routed to combustion, paragraphs (o)(1) through (11) of this section do not apply and instead you must calculate and report emissions as specified in subpart C of this part or paragraph (z) of this section, as applicable. If emissions from a compressor source are routed to a vapor recovery system, paragraphs (o)(1) through (11) of this section do not apply.
                            </P>
                            <P>(1) General requirements for conducting volumetric emission measurements. You must conduct volumetric emission measurements on each centrifugal compressor as specified in this paragraph. Compressor sources (as defined in § 98.238) without manifolded vents must use a measurement method specified in paragraph (o)(1)(i) or (ii) of this section. Manifolded compressor sources (as defined in § 98.238) must use a measurement method specified in paragraph (o)(1)(i), (ii), (iii), or (iv) of this section.</P>
                            <P>
                                (i) 
                                <E T="03">Centrifugal compressor source as found measurements.</E>
                                 Measure venting from each compressor according to either paragraph (o)(1)(i)(A), (B), or (C) of this section at least once annually, based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement, except as specified in paragraph (o)(1)(i)(D) of this section. If additional measurements beyond the required annual testing are performed (including duplicate measurements or measurement of additional operating modes), then all measurements satisfying the applicable monitoring and QA/QC that is required by this paragraph (o) must be used in the calculations specified in this section.
                            </P>
                            <P>(A) For a compressor measured in operating-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in paragraph (o)(2)(i) of this section, measure volumetric emissions from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section if the compressor has wet seal oil degassing vents, and measure volumetric emissions from dry seal vents as specified in paragraph (o)(2)(iii) of this section if the compressor has dry seals.</P>
                            <P>(B) For a compressor measured in not-operating-depressurized-mode, you must measure volumetric emissions from isolation valve leakage as specified in paragraph (o)(2)(i) of this section. If a compressor is not operated and has blind flanges in place throughout the reporting period, measurement is not required in this compressor mode.</P>
                            <P>(C) For a compressor measured in standby-pressurized-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in paragraph (o)(2)(i) of this section, measure volumetric emissions from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section if the compressor has wet seal oil degassing vents, and measure volumetric emissions from dry seal vents as specified in paragraph (o)(2)(iii) of this section if the compressor has dry seals.</P>
                            <P>(D) An annual as found measurement is not required in the first year of operation for any new compressor that begins operation after as found measurements have been conducted for all existing compressors. For only the first year of operation of new compressors, calculate emissions according to paragraph (o)(6)(ii) of this section.</P>
                            <P>
                                (ii) 
                                <E T="03">Centrifugal compressor source continuous monitoring.</E>
                                 Instead of measuring the compressor source according to paragraph (o)(1)(i) of this section for a given compressor, you may elect to continuously measure volumetric emissions from a compressor source as specified in paragraph (o)(3) of this section.
                            </P>
                            <P>
                                (iii) 
                                <E T="03">Manifolded centrifugal compressor source as found measurements.</E>
                                 For a compressor source that is part of a manifolded group of compressor sources (as defined in § 98.238), instead of measuring the compressor source according to paragraph (o)(1)(i), (ii), or (iv) of this section, you may elect to measure combined volumetric emissions from the manifolded group of compressor sources by conducting measurements at the common vent stack as specified in paragraph (o)(4) of this section. The measurements must be conducted at the frequency specified in paragraphs (o)(1)(iii)(A) and (B) of this section.
                            </P>
                            <P>(A) A minimum of one measurement must be taken for each manifolded group of compressor sources in a calendar year.</P>
                            <P>(B) The measurement may be performed while the compressors are in any compressor mode.</P>
                            <P>
                                (iv) 
                                <E T="03">Manifolded centrifugal compressor source continuous monitoring.</E>
                                 For a compressor source that is part of a manifolded group of compressor sources, instead of measuring the compressor source according to paragraph (o)(1)(i), (ii), or (iii) of this section, you may elect to continuously measure combined volumetric emissions from the manifolded group of compressor sources as specified in paragraph (o)(5) of this section.
                            </P>
                            <P>
                                (2) 
                                <E T="03">Methods for performing as found measurements from individual centrifugal compressor sources</E>
                                . If conducting measurements for each compressor source, you must determine the volumetric emissions from blowdown valves and isolation valves as specified in paragraph (o)(2)(i) of this section, the volumetric emissions from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section, and the volumetric emissions from dry seal vents as specified in paragraph (o)(2)(iii) of this section.
                            </P>
                            <P>(i) For blowdown valves on compressors in operating-mode or in standby-pressurized-mode and for isolation valves on compressors in not-operating-depressurized-mode, determine the volumetric emissions using one of the methods specified in paragraphs (o)(2)(i)(A) through (D) of this section.</P>
                            <P>(A) Determine the volumetric flow at standard conditions from the blowdown vent using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and § 98.234(d), respectively.</P>
                            <P>(B) Determine the volumetric flow at standard conditions from the blowdown vent using a temporary meter such as a vane anemometer according to methods set forth in § 98.234(b).</P>
                            <P>(C) Use an acoustic leak detection device according to methods set forth in § 98.234(a)(5).</P>
                            <P>(D) You may choose to use any of the methods set forth in § 98.234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must use one of the methods specified in paragraph (o)(2)(i)(A) through (C) of this section. If emissions are not detected using the methods in § 98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the methods.</P>
                            <P>
                                (ii) For wet seal oil degassing vents in operating-mode or in standby-pressurized-mode, determine volumetric flow at standard conditions, using one of the methods specified in paragraphs (o)(2)(ii)(A) through (C) of this section. You must quantitatively measure the volumetric flow for wet seal oil degassing vent; you may not use screening methods set forth in 
                                <PRTPAGE P="42267"/>
                                § 98.234(a) to screen for emissions for the wet seal oil degassing vent.
                            </P>
                            <P>(A) Use a temporary meter such as a vane anemometer or permanent flow meter according to methods set forth in § 98.234(b).</P>
                            <P>(B) Use calibrated bags according to methods set forth in § 98.234(c).</P>
                            <P>(C) Use a high volume sampler according to methods set forth in § 98.234(d).</P>
                            <P>(iii) For dry seal vents in operating-mode or in standby-pressurized-mode, determine volumetric flow at standard conditions from each dry seal vent using one of the methods specified in paragraphs (o)(2)(iii)(A) through (D) of this section. The measurement should be conducted on the compressor side dry seal. If a compressor has more than one dry seal vent, determine the aggregate dry seal vent volumetric flow for the compressor as the sum of the volumetric flows determined for each dry seal vent on the compressor.</P>
                            <P>(A) Use a temporary meter such as a vane anemometer or permanent flow meter according to methods set forth in § 98.234(b).</P>
                            <P>(B) Use calibrated bags according to methods set forth in § 98.234(c).</P>
                            <P>(C) Use a high volume sampler according to methods set forth in § 98.234(d).</P>
                            <P>(D) You may choose to use any of the methods set forth in § 98.234(a)(1) through (3) to screen for emissions. If emissions are detected using one of these specified methods, then you must use one of the methods specified in paragraph (o)(2)(iii)(A) through (C) of this section. If emissions are not detected using the methods in § 98.234(a)(1) through (3), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the methods. Acoustic leak detection is only applicable for through-valve leakage and is not applicable for screening dry seal vents.</P>
                            <P>
                                (3) 
                                <E T="03">Methods for continuous measurement from individual centrifugal compressor sources.</E>
                                 If you elect to conduct continuous volumetric emission measurements for an individual compressor source as specified in paragraph (o)(1)(ii) of this section, you must measure volumetric emissions as specified in paragraphs (o)(3)(i) and (ii) of this section.
                            </P>
                            <P>(i) Continuously measure the volumetric flow for the individual compressor source at standard conditions using a permanent meter according to methods set forth in § 98.234(b).</P>
                            <P>(ii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (o)(3)(i) of this section, the compressor blowdown emissions may be included with the reported emissions for the compressor source and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks.</P>
                            <P>
                                (4) 
                                <E T="03">Methods for performing as found measurements from manifolded groups of centrifugal compressor sources.</E>
                                 If conducting measurements for a manifolded group of compressor sources, you must measure volumetric emissions as specified in paragraphs (o)(4)(i) and (ii) of this section.
                            </P>
                            <P>(i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, prior to comingling with other non-compressor emission sources.</P>
                            <P>(ii) Determine the volumetric flow at standard conditions from the common stack using one of the methods specified in paragraphs (o)(4)(ii)(A) through (F) of this section.</P>
                            <P>(A) A temporary meter such as a vane anemometer according the methods set forth in § 98.234(b).</P>
                            <P>(B) Calibrated bagging according to methods set forth in § 98.234(c).</P>
                            <P>(C) A high volume sampler according to methods set forth § 98.234(d).</P>
                            <P>(D) [Reserved]</P>
                            <P>(E) You may choose to use any of the methods set forth in § 98.234(a)(1) through (3) to screen for emissions. If emissions are detected using one of these methods, then you must use one of the methods specified in paragraph (o)(4)(ii)(A) through (D) of this section. If emissions are not detected using the methods in § 98.234(a)(1) through (3), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method. Acoustic leak detection is only applicable for through-valve leakage and is not applicable for screening a manifolded group of compressor sources.</P>
                            <P>(F) If one of the screening methods specified in § 98.234(a)(1) through (3) identifies a leak in a manifolded group of centrifugal compressor sources, you may use acoustic leak detection, according to § 98.234(a)(5), to identify the source of the leak. You must use one of the methods specified in paragraphs (o)(4)(ii)(A) through (D) of this section to quantify emissions from the identified source.</P>
                            <P>
                                (5) 
                                <E T="03">Methods for continuous measurement from manifolded groups of centrifugal compressor sources.</E>
                                 If you elect to conduct continuous volumetric emission measurements for a manifolded group of compressor sources as specified in paragraph (o)(1)(iv) of this section, you must measure volumetric emissions as specified in paragraphs (o)(5)(i) through (iii) of this section.
                            </P>
                            <P>(i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, prior to comingling with other non-compressor emission sources.</P>
                            <P>(ii) Continuously measure the volumetric flow for the manifolded group of compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b).</P>
                            <P>(iii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (o)(5)(ii) of this section, the compressor blowdown emissions may be included with the reported emissions for the manifolded group of compressor sources and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks.</P>
                            <P>
                                (6) 
                                <E T="03">Method for calculating volumetric GHG emissions from as found measurements for individual centrifugal compressor sources</E>
                                . For compressor sources measured according to paragraph (o)(1)(i) of this section, you must calculate annual GHG emissions from the compressor sources as specified in paragraphs (o)(6)(i) through (iv) of this section.
                            </P>
                            <P>(i) Using equation W-21 to this section, calculate the annual volumetric GHG emissions for each centrifugal compressor mode-source combination specified in paragraphs (o)(1)(i)(A) through (C) of this section that was measured during the reporting year.</P>
                            <GPH SPAN="3" DEEP="15">
                                <GID>ER14MY24.077</GID>
                            </GPH>
                            <EXTRACT>
                                <PRTPAGE P="42268"/>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,m</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions for measured compressor mode-source combination m, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    MT
                                    <E T="52">s,m</E>
                                     = Volumetric gas emissions for measured compressor mode-source combination m, in standard cubic feet per hour, measured according to paragraph (o)(2) of this section. If multiple measurements are performed for a given mode-source combination m, use the average of all measurements.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">m</E>
                                     = Total time the compressor is in the mode-source combination for which Es,i,m is being calculated in the reporting year, in hours.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i,m</E>
                                     = Mole fraction of GHG
                                    <E T="52">i</E>
                                     in the vent gas for measured compressor mode-source combination m; use the appropriate gas compositions in paragraph (u)(2) of this section.
                                </FP>
                                <FP SOURCE="FP-2">m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A), (B), or (C) of this section that was measured for the reporting year.</FP>
                            </EXTRACT>
                            <P>(ii) Using equation W-22 to this section, calculate the annual volumetric GHG emissions from each centrifugal compressor mode-source combination specified in paragraphs (o)(1)(i)(A) through (C) of this section that was not measured during the reporting year.</P>
                            <GPH SPAN="3" DEEP="15">
                                <GID>ER14MY24.078</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,m</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions for unmeasured compressor mode-source combination m, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">s,m</E>
                                     = Reporter emission factor for compressor mode-source combination m, in standard cubic feet per hour, as calculated in paragraph (o)(6)(iii) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">m</E>
                                     = Total time the compressor was in the unmeasured mode-source combination m, for which Es,i,m is being calculated in the reporting year, in hours.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i,m</E>
                                     = Mole fraction of GHG
                                    <E T="52">i</E>
                                     in the vent gas for unmeasured compressor mode-source combination m; use the appropriate gas compositions in paragraph (u)(2) of this section.
                                </FP>
                                <FP SOURCE="FP-2">m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A), (B), or (C) of this section that was not measured in the reporting year.</FP>
                            </EXTRACT>
                            <P>(iii) Using equation W-23 to this section, develop an emission factor for each compressor mode-source combination specified in paragraphs (o)(1)(i)(A) through (C) of this section. These emission factors must be calculated annually and used in equation W-22 to this section to determine volumetric emissions from a centrifugal compressor in the mode-source combinations that were not measured in the reporting year.</P>
                            <EXTRACT>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">s,m</E>
                                     = Reporter emission factor to be used in equation W-22 to this section for compressor mode-source combination m, in standard cubic feet per hour. The reporter emission factor must be based on all compressors measured in compressor mode-source combination m in the current reporting year and the preceding two reporting years.
                                </FP>
                                <FP SOURCE="FP-2">
                                    MT
                                    <E T="52">s,m,p</E>
                                     = Average volumetric gas emission measurement for compressor mode-source combination m, for compressor p, in standard cubic feet per hour, calculated using all volumetric gas emission measurements (MT
                                    <E T="52">s,m</E>
                                     in equation W-21 to this section) for compressor mode-source combination m for compressor p in the current reporting year and the preceding two reporting years.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Count
                                    <E T="52">m</E>
                                     = Total number of compressors measured in compressor mode-source combination m in the current reporting year and the preceding two reporting years.
                                </FP>
                                <FP SOURCE="FP-2">m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A), (B), or (C) of this section.</FP>
                            </EXTRACT>
                            <P>(iv) The reporter emission factor in equation W-23 to this section may be calculated by using all measurements from a single owner or operator instead of only using measurements from a single facility. If you elect to use this option, the reporter emission factor must be applied to all reporting facilities for the owner or operator.</P>
                            <P>
                                (7) 
                                <E T="03">Method for calculating volumetric GHG emissions from continuous monitoring of individual centrifugal compressor sources</E>
                                . For compressor sources measured according to paragraph (o)(1)(ii) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (o)(3) of this section and calculate annual volumetric GHG emissions associated with the compressor source using equation W-24A to this section.
                            </P>
                            <GPH SPAN="3" DEEP="15">
                                <GID>ER14MY24.079</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,v</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions from compressor source v, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Q
                                    <E T="52">s,v</E>
                                     = Volumetric gas emissions from compressor source v, for reporting year, in standard cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i,v</E>
                                     = Mole fraction of GHG
                                    <E T="52">i</E>
                                     in the vent gas for compressor source v; use the appropriate gas compositions in paragraph (u)(2) of this section.
                                </FP>
                            </EXTRACT>
                            <P>
                                (8) 
                                <E T="03">Method for calculating volumetric GHG emissions from as found measurements of manifolded groups of centrifugal compressor sources</E>
                                . For manifolded groups of compressor sources measured according to paragraph (o)(1)(iii) of this section, you must calculate annual volumetric GHG emissions using equation W-24B to this section. If the centrifugal compressors included in the manifolded group of compressor sources share the manifold with reciprocating compressors, you must follow the procedures in either this paragraph (o)(8) or paragraph (p)(8) of this section to calculate emissions from the manifolded group of compressor sources.
                            </P>
                            <GPH SPAN="3" DEEP="15">
                                <GID>ER14MY24.080</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,g</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions for manifolded group of compressor sources g, at standard conditions, in cubic feet. T
                                    <E T="52">g</E>
                                     = Total time the manifolded group of compressor sources g had potential for emissions in the reporting year, in hours. Include all time during which at least one compressor source in the manifolded group of compressor sources g was in a mode-source combination specified in either paragraph (o)(1)(i)(A), (o)(1)(i)(B), (o)(1)(i)(C), (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section. Default of 
                                    <PRTPAGE P="42269"/>
                                    8760 hours may be used. MT
                                    <E T="52">s,g,avg</E>
                                     = Average volumetric gas emissions of all measurements performed in the reporting year according to paragraph (o)(4) of this section for the manifolded group of compressor sources g, in standard cubic feet per hour.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i,g</E>
                                     = Mole fraction of GHG
                                    <E T="52">i</E>
                                     in the vent gas for manifolded group of compressor sources g; use the appropriate gas compositions in paragraph (u)(2) of this section.
                                </FP>
                            </EXTRACT>
                            <P>
                                (9) 
                                <E T="03">Method for calculating volumetric GHG emissions from continuous monitoring of manifolded group of centrifugal compressor sources.</E>
                                 For a manifolded group of compressor sources measured according to paragraph (o)(1)(iv) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (o)(5) of this section and calculate annual volumetric GHG emissions associated with each manifolded group of compressor sources using equation W-24C to this section. If the centrifugal compressors included in the manifolded group of compressor sources share the manifold with reciprocating compressors, you must follow the procedures in either this paragraph (o)(9) or paragraph (p)(9) of this section to calculate emissions from the manifolded group of compressor sources.
                            </P>
                            <GPH SPAN="3" DEEP="15">
                                <GID>ER14MY24.081</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,g</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions from manifolded group of compressor sources g, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Q
                                    <E T="52">s,g</E>
                                     = Volumetric gas emissions from manifolded group of compressor sources g, for reporting year, in standard cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i,g</E>
                                     = Mole fraction of GHG
                                    <E T="52">i</E>
                                     in the vent gas for measured manifolded group of compressor sources g; use the appropriate gas compositions in paragraph (u)(2) of this section.
                                </FP>
                            </EXTRACT>
                            <P>
                                (10) 
                                <E T="03">Method for calculating volumetric GHG emissions from wet seal oil degassing vents at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility.</E>
                                 You must calculate volumetric emissions from centrifugal compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility as specified in paragraphs (o)(10)(i) through (iv), as applicable.
                            </P>
                            <P>(i) For all centrifugal compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility that are subject to the centrifugal compressor standards in § 60.5380b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter for dry seals and self-contained wet seals, you must conduct the volumetric emission measurements as required by § 60.5380b(a)(5) of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, conduct all additional volumetric emission measurements specified in paragraph (o)(1) of this section using methods specified in paragraphs (o)(2) through (5) of this section (based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement), and calculate emissions as specified in paragraphs (o)(6) through (9) of this section. Conduct all measurements required by this paragraph (o)(10)(i) at the frequency specified by § 60.5380b(a)(4) of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter. For any reporting year in which measuring at the frequency specified by § 60.5380b(a)(4) of this chapter results in measurement not being required for a subject compressor, calculate emissions for all mode-source combinations as specified in paragraph (o)(6)(ii) of this section.</P>
                            <P>(ii) For all centrifugal compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility that are not subject to the centrifugal compressor standards in § 60.5380b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter for dry seals and self-contained wet seals, you may elect to conduct the volumetric emission measurements specified in paragraph (o)(1) of this section using methods specified in paragraphs (o)(2) through (5) of this section (based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement), and calculate emissions as specified in paragraphs (o)(6) through (9) of this section.</P>
                            <P>(iii) For all centrifugal compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility for which paragraph (o)(10)(i) of this section does not apply and you do not elect to conduct the volumetric measurements specified in paragraph (o)(1) of this section, you must calculate total atmospheric wet seal oil degassing vent emissions from all centrifugal compressors at either an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility using equation W-25A to this section. Emissions from centrifugal compressor wet seal oil degassing vents that are routed to a flare, combustion, or vapor recovery system are not required to be determined under this paragraph (o).</P>
                            <GPH SPAN="3" DEEP="43">
                                <GID>ER14MY24.082</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions from all centrifugal compressors, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">Count = Total number of centrifugal compressors with wet seal oil degassing vents that are vented directly to the atmosphere.</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,p</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions for centrifugal compressor p, at standard conditions, in cubic feet, calculated using equation W-25B to this section.
                                </FP>
                            </EXTRACT>
                            <P>
                                (iv) For all centrifugal compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility for which paragraph (o)(10)(i) of this section does not apply, 
                                <PRTPAGE P="42270"/>
                                and you do not elect to conduct the volumetric measurements specified in paragraph (o)(1) of this section, you must calculate wet seal oil degassing vent emissions from each centrifugal compressor using equation W-25B to this section. Emissions from centrifugal compressor wet seal oil degassing vents that are routed to a flare, combustion, or vapor recovery system are not required to be determined under this paragraph (o).
                            </P>
                            <GPH SPAN="3" DEEP="35">
                                <GID>ER14MY24.083</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,p</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions for centrifugal compressor p, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">s,p</E>
                                     = Emission factor for centrifugal compressor p, in standard cubic feet per year. Use 1.2 × 107 standard cubic feet per year per compressor for CH
                                    <E T="52">4</E>
                                     and 5.30 × 105 standard cubic feet per year per compressor for CO
                                    <E T="52">2</E>
                                     at 60 °F and 14.7 psia.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">p</E>
                                     = Total time centrifugal compressor p was in operating mode, for which Es,i,p is being calculated in the reporting year, in hours.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">total</E>
                                     = Total hours per year. Use 8784 in leap years and use 8760 in all other years.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i,p</E>
                                     = Mole fraction of GHG (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) in the vent gas for centrifugal compressor p in operating mode; use the appropriate gas compositions in paragraph (u)(2) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">EF</E>
                                     = Mole fraction of GHG (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) used in the determination of EF
                                    <E T="52">s,p</E>
                                    . Use 0.95 for CH
                                    <E T="52">4</E>
                                     and 0.05 for CO
                                    <E T="52">2</E>
                                    .
                                </FP>
                            </EXTRACT>
                            <P>
                                (11) 
                                <E T="03">Method for converting from volumetric to mass emissions</E>
                                . You must calculate both CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.
                            </P>
                            <P>
                                (p) 
                                <E T="03">Reciprocating compressor venting.</E>
                                 If you are required to report emissions from reciprocating compressor venting as specified in § 98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), you must conduct volumetric emission measurements specified in paragraph (p)(1) of this section using methods specified in paragraphs (p)(2) through (5) of this section; perform calculations specified in paragraphs (p)(6) through (9) of this section; and calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions as specified in paragraph (p)(11) of this section. If you are required to report emissions from reciprocating compressor venting at an onshore petroleum and natural gas production facility as specified in § 98.232(c)(11) or an onshore petroleum and natural gas gathering and boosting facility as specified in § 98.232(j)(9), you must calculate volumetric emissions as specified in paragraph (p)(10) of this section and calculate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions as specified in paragraph (p)(11) of this section. If emissions from a compressor source are routed to a flare, paragraphs (p)(1) through (11) of this section do not apply and instead you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O emissions as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n). If emissions from a compressor source are routed to combustion, paragraphs (p)(1) through (11) of this section do not apply and instead you must calculate and report emissions as specified in subpart C of this part or paragraph (z) of this section, as applicable. If emissions from a compressor source are routed to a vapor recovery system, paragraphs (p)(1) through (11) of this section do not apply.
                            </P>
                            <P>
                                (1) 
                                <E T="03">General requirements for conducting volumetric emission measurements.</E>
                                 You must conduct volumetric emission measurements on each reciprocating compressor as specified in this paragraph. Compressor sources (as defined in § 98.238) without manifolded vents must use a measurement method specified in paragraph (p)(1)(i) or (ii) of this section. Manifolded compressor sources (as defined in § 98.238) must use a measurement method specified in paragraph (p)(1)(i), (ii), (iii), or (iv) of this section.
                            </P>
                            <P>
                                (i) 
                                <E T="03">Reciprocating compressor source as found measurements.</E>
                                 Measure venting from each compressor according to either paragraph (p)(1)(i)(A), (B), or (C) of this section at least once annually, based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement, except as specified in paragraph (p)(1)(i)(D) of this section. If additional measurements beyond the required annual testing are performed (including duplicate measurements or measurement of additional operating modes), then all measurements satisfying the applicable monitoring and QA/QC that is required by this paragraph (p) must be used in the calculations specified in this section.
                            </P>
                            <P>(A) For a compressor measured in operating-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in paragraph (p)(2)(i) of this section, and measure volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) or (iii) of this section, as applicable.</P>
                            <P>(B) For a compressor measured in not-operating-depressurized-mode, you must measure volumetric emissions from isolation valve leakage as specified in paragraph (p)(2)(i) of this section. If a compressor is not operated and has blind flanges in place throughout the reporting period, measurement is not required in this compressor mode.</P>
                            <P>(C) For a compressor measured in standby-pressurized-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in paragraph (p)(2)(i) of this section and measure volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) or (iii) of this section, as applicable.</P>
                            <P>(D) An annual as found measurement is not required in the first year of operation for any new compressor that begins operation after as found measurements have been conducted for all existing compressors. For only the first year of operation of new compressors, calculate emissions according to paragraph (p)(6)(ii) of this section.</P>
                            <P>
                                (ii) 
                                <E T="03">Reciprocating compressor source continuous monitoring.</E>
                                 Instead of measuring the compressor source according to paragraph (p)(1)(i) of this section for a given compressor, you may elect to continuously measure volumetric emissions from a compressor source as specified in paragraph (p)(3) of this section.
                            </P>
                            <P>
                                (iii) 
                                <E T="03">Manifolded reciprocating compressor source as found measurements.</E>
                                 For a compressor source that is part of a manifolded group of compressor sources (as defined in § 98.238), instead of measuring the compressor source according to paragraph (p)(1)(i), (ii), or (iv) of this section, you may elect to measure combined volumetric emissions from the manifolded group of compressor sources by conducting measurements at the common vent stack as specified in paragraph (p)(4) of this section. The measurements must be conducted at the 
                                <PRTPAGE P="42271"/>
                                frequency specified in paragraphs (p)(1)(iii)(A) and (B) of this section.
                            </P>
                            <P>(A) A minimum of one measurement must be taken for each manifolded group of compressor sources in a calendar year.</P>
                            <P>(B) The measurement may be performed while the compressors are in any compressor mode.</P>
                            <P>
                                (iv) 
                                <E T="03">Manifolded reciprocating compressor source continuous monitoring.</E>
                                 For a compressor source that is part of a manifolded group of compressor sources, instead of measuring the compressor source according to paragraph (p)(1)(i), (ii), or (iii) of this section, you may elect to continuously measure combined volumetric emissions from the manifolded group of compressors sources as specified in paragraph (p)(5) of this section.
                            </P>
                            <P>
                                (2) 
                                <E T="03">Methods for performing as found measurements from individual reciprocating compressor sources</E>
                                . If conducting measurements for each compressor source, you must determine the volumetric emissions from blowdown valves and isolation valves as specified in paragraph (p)(2)(i) of this section. You must determine the volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) or (iii) of this section, as applicable.
                            </P>
                            <P>
                                (i) 
                                <E T="03">For blowdown valves on compressors in operating-mode or standby-pressurized-mode,</E>
                                 and for isolation valves on compressors in not-operating-depressurized-mode, determine the volumetric emissions using one of the methods specified in paragraphs (p)(2)(i)(A) through (D) of this section.
                            </P>
                            <P>(A) Determine the volumetric flow at standard conditions from the blowdown vent using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and (d), respectively.</P>
                            <P>(B) Determine the volumetric flow at standard conditions from the blowdown vent using a temporary meter such as a vane anemometer, according to methods set forth in § 98.234(b).</P>
                            <P>(C) Use an acoustic leak detection device according to methods set forth in § 98.234(a)(5).</P>
                            <P>(D) You may choose to use any of the methods set forth in § 98.234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must use one of the methods specified in paragraphs (p)(2)(i)(A) through (C) of this section. If emissions are not detected using the methods in § 98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method.</P>
                            <P>(ii) For reciprocating rod packing equipped with an open-ended vent line on compressors in operating-mode or standby-pressurized-mode, determine the volumetric emissions using one of the methods specified in paragraphs (p)(2)(ii)(A) through (C) of this section.</P>
                            <P>(A) Determine the volumetric flow at standard conditions from the open-ended vent line using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and (d), respectively.</P>
                            <P>(B) Determine the volumetric flow at standard conditions from the open-ended vent line using a temporary meter such as a vane anemometer, according to methods set forth in § 98.234(b).</P>
                            <P>(C) You may choose to use any of the methods set forth in § 98.234(a)(1) through (3) to screen for emissions. If emissions are detected using one of these specified methods, then you must use one of the methods specified in paragraphs (p)(2)(ii)(A) and (B) of this section. If emissions are not detected using the methods in § 98.234(a)(1) through (3), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph (p)(2)(ii)(C), when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method. Acoustic leak detection is only applicable for through-valve leakage and is not applicable for screening or measuring rod packing emissions.</P>
                            <P>(iii) For reciprocating rod packing not equipped with an open-ended vent line on compressors in operating-mode, you must determine the volumetric emissions using the method specified in paragraphs (p)(2)(iii)(A) and (B) of this section.</P>
                            <P>(A) You must use the methods described in § 98.234(a)(1) through (3) to conduct annual leak detection of equipment leaks from the packing case into an open distance piece, or for compressors with a closed distance piece, conduct annual detection of gas emissions from the rod packing vent, distance piece vent, compressor crank case breather cap, or other vent emitting gas from the rod packing. Acoustic leak detection is only applicable for through-valve leakage and is not applicable for screening rod packing emissions.</P>
                            <P>(B) You must measure emissions found in paragraph (p)(2)(iii)(A) of this section using an appropriate meter, calibrated bag, or high volume sampler according to methods set forth in § 98.234(b), (c), and (d), respectively.</P>
                            <P>
                                (3) 
                                <E T="03">Methods for continuous measurement from individual reciprocating compressor sources</E>
                                . If you elect to conduct continuous volumetric emission measurements for an individual compressor source as specified in paragraph (p)(1)(ii) of this section, you must measure volumetric emissions as specified in paragraphs (p)(3)(i) and (p)(3)(ii) of this section.
                            </P>
                            <P>(i) Continuously measure the volumetric flow for the individual compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b).</P>
                            <P>(ii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (p)(3)(i) of this section, the compressor blowdown emissions may be included with the reported emissions for the compressor source and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks.</P>
                            <P>
                                (4) 
                                <E T="03">Methods for performing as found measurements from manifolded groups of reciprocating compressor sources</E>
                                . If conducting measurements for a manifolded group of compressor sources, you must measure volumetric emissions as specified in paragraphs (p)(4)(i) and (ii) of this section.
                            </P>
                            <P>(i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, prior to comingling with other non-compressor emission sources.</P>
                            <P>(ii) Determine the volumetric flow at standard conditions from the common stack using one of the methods specified in paragraph (p)(4)(ii)(A) through (F) of this section.</P>
                            <P>(C) A high volume sampler according to methods set forth in § 98.234(d).</P>
                            <P>(D) [Reserved]</P>
                            <P>(E) You may choose to use any of the methods set forth in § 98.234(a)(1) through (3) to screen for emissions. If emissions are detected using one of these specified methods, then you must use one of the methods specified in paragraphs (p)(4)(ii)(A) through (D) of this section. If emissions are not detected using the methods in § 98.234(a)(1) through (3), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method. Acoustic leak detection is only applicable for through-valve leakage and is not applicable for screening a manifolded group of compressor sources.</P>
                            <P>
                                (F) If one of the screening methods specified in § 98.234(a)(1) through (3) 
                                <PRTPAGE P="42272"/>
                                identifies a leak in a manifolded group of reciprocating compressor sources, you may use acoustic leak detection, according to § 98.234(a)(5), to identify the source of the leak. You must use one of the methods specified in paragraphs (p)(4)(ii)(A) through (D) of this section to quantify the emissions from the identified source.
                            </P>
                            <P>
                                (5) 
                                <E T="03">Methods for continuous measurement from manifolded groups of reciprocating compressor sources</E>
                                . If you elect to conduct continuous volumetric emission measurements for a manifolded group of compressor sources as specified in paragraph (p)(1)(iv) of this section, you must measure volumetric emissions as specified in paragraphs (p)(5)(i) through (iii) of this section.
                            </P>
                            <P>(i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, prior to comingling with other non-compressor emission sources.</P>
                            <P>(ii) Continuously measure the volumetric flow for the manifolded group of compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b).</P>
                            <P>(iii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (p)(5)(ii) of this section, the compressor blowdown emissions may be included with the reported emissions for the manifolded group of compressor sources and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks.</P>
                            <P>
                                (6) 
                                <E T="03">Method for calculating volumetric GHG emissions from as found measurements for individual reciprocating compressor sources</E>
                                . For compressor sources measured according to paragraph (p)(1)(i) of this section, you must calculate GHG emissions from the compressor sources as specified in paragraphs (p)(6)(i) through (iv) of this section.
                            </P>
                            <P>(i) Using equation W-26 to this section, calculate the annual volumetric GHG emissions for each reciprocating compressor mode-source combination specified in paragraphs (p)(1)(i)(A) through (C) of this section that was measured during the reporting year.</P>
                            <GPH SPAN="3" DEEP="15">
                                <GID>ER14MY24.084</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,m</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions for measured compressor mode-source combination m, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    MT
                                    <E T="52">s,m</E>
                                     = Volumetric gas emissions for measured compressor mode-source combination m, in standard cubic feet per hour, measured according to paragraph (p)(2) of this section. If multiple measurements are performed for a given mode-source combination m, use the average of all measurements.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">m</E>
                                     = Total time the compressor is in the mode-source combination m, for which Es,i,m is being calculated in the reporting year, in hours.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i,m</E>
                                     = Mole fraction of GHG
                                    <E T="52">i</E>
                                     in the vent gas for measured compressor mode-source combination m; use the appropriate gas compositions in paragraph (u)(2) of this section.
                                </FP>
                                <FP SOURCE="FP-2">m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), (B), or (C) of this section that was measured for the reporting year.</FP>
                            </EXTRACT>
                            <P>(ii) Using equation W-27 to this section, calculate the annual volumetric GHG emissions from each reciprocating compressor mode-source combination specified in paragraphs (p)(1)(i)(A) through (C) of this section that was not measured during the reporting year.</P>
                            <GPH SPAN="3" DEEP="15">
                                <GID>ER14MY24.085</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,m</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions for unmeasured compressor mode-source combination m, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">s,m</E>
                                     = Reporter emission factor for compressor mode-source combination m, in standard cubic feet per hour, as calculated in paragraph (p)(6)(iii) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">m</E>
                                     = Total time the compressor was in the unmeasured mode-source combination m, for which Es,i,m is being calculated in the reporting year, in hours.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i,m</E>
                                     = Mole fraction of GHG
                                    <E T="52">i</E>
                                     in the vent gas for unmeasured compressor mode-source combination m; use the appropriate gas compositions in paragraph (u)(2) of this section.
                                </FP>
                                <FP SOURCE="FP-2">m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section that was not measured for the reporting year.</FP>
                            </EXTRACT>
                            <P>(iii) Using equation W-28 to this section, develop an emission factor for each compressor mode-source combination specified in paragraphs (p)(1)(i)(A) through (C) of this section. These emission factors must be calculated annually and used in equation W-27 to this section to determine volumetric emissions from a reciprocating compressor in the mode-source combinations that were not measured in the reporting year.</P>
                            <GPH SPAN="3" DEEP="52">
                                <GID>ER14MY24.086</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">s,m</E>
                                     = Reporter emission factor to be used in equation W-27 to this section for compressor mode-source combination m, in standard cubic feet per hour. The reporter emission factor must be based on all compressors measured in compressor mode-source combination m in the current reporting year and the preceding two reporting years.
                                </FP>
                                <FP SOURCE="FP-2">
                                    MT
                                    <E T="52">s,m,p</E>
                                     = Average volumetric gas emission measurement for compressor mode-source combination m, for compressor p, in standard cubic feet per hour, calculated using all volumetric gas emission measurements (MT
                                    <E T="52">s,m</E>
                                     in equation W-26 to this section) for compressor mode-source combination m for compressor p in the current reporting year and the preceding two reporting years.
                                    <PRTPAGE P="42273"/>
                                </FP>
                                <FP SOURCE="FP-2">
                                    Count
                                    <E T="52">m</E>
                                     = Total number of compressors measured in compressor mode-source combination m in the current reporting year and the preceding two reporting years.
                                </FP>
                                <FP SOURCE="FP-2">m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), (B), or (C) of this section.</FP>
                            </EXTRACT>
                            <P>(iv) The reporter emission factor in equation W-28 to this section may be calculated by using all measurements from a single owner or operator instead of only using measurements from a single facility. If you elect to use this option, the reporter emission factor must be applied to all reporting facilities for the owner or operator.</P>
                            <P>
                                (7) 
                                <E T="03">Method for calculating volumetric GHG emissions from continuous monitoring of individual reciprocating compressor sources</E>
                                . For compressor sources measured according to paragraph (p)(1)(ii) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (p)(3) of this section and calculate annual volumetric GHG emissions associated with the compressor source using equation W-29A to this section.
                            </P>
                            <GPH SPAN="3" DEEP="15">
                                <GID>ER14MY24.087</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,v</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions from compressor source v, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Q
                                    <E T="52">s,v</E>
                                     = Volumetric gas emissions from compressor source v, for reporting year, in standard cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i,v</E>
                                     = Mole fraction of GHG
                                    <E T="52">i</E>
                                     in the vent gas for compressor source v; use the appropriate gas compositions in paragraph (u)(2) of this section.
                                </FP>
                            </EXTRACT>
                            <P>
                                (8) 
                                <E T="03">Method for calculating volumetric GHG emissions from as found measurements of manifolded groups of reciprocating compressor sources.</E>
                                 For manifolded groups of compressor sources measured according to paragraph (p)(1)(iii) of this section, you must calculate annual GHG emissions using equation W-29B to this section. If the reciprocating compressors included in the manifolded group of compressor sources share the manifold with centrifugal compressors, you must follow the procedures in either this paragraph (p)(8) or paragraph (o)(8) of this section to calculate emissions from the manifolded group of compressor sources.
                            </P>
                            <GPH SPAN="3" DEEP="15">
                                <GID>ER14MY24.088</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,g</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions for manifolded group of compressor sources g, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">g</E>
                                     = Total time the manifolded group of compressor sources g had potential for emissions in the reporting year, in hours. Include all time during which at least one compressor source in the manifolded group of compressor sources g was in a mode-source combination specified in either paragraph (o)(1)(i)(A), (o)(1)(i)(B), (o)(1)(i)(C), (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section. Default of 8760 hours may be used.
                                </FP>
                                <FP SOURCE="FP-2">
                                    MT
                                    <E T="52">s,g,avg</E>
                                     = Average volumetric gas emissions of all measurements performed in the reporting year according to paragraph (p)(4) of this section for the manifolded group of compressor sources g, in standard cubic feet per hour.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i,g</E>
                                     = Mole fraction of GHG
                                    <E T="52">i</E>
                                     in the vent gas for manifolded group of compressor sources g; use the appropriate gas compositions in paragraph (u)(2) of this section.
                                </FP>
                            </EXTRACT>
                            <P>
                                (9) 
                                <E T="03">Method for calculating volumetric GHG emissions from continuous monitoring of manifolded group of reciprocating compressor sources</E>
                                . For a manifolded group of compressor sources measured according to paragraph (p)(1)(iv) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (p)(5) of this section and calculate annual volumetric GHG emissions associated with each manifolded group of compressor sources using equation W-29C to this section. If the reciprocating compressors included in the manifolded group of compressor sources share the manifold with centrifugal compressors, you must follow the procedures in either this paragraph (p)(9) or paragraph (o)(9) of this section to calculate emissions from the manifolded group of compressor sources.
                            </P>
                            <GPH SPAN="3" DEEP="15">
                                <GID>ER14MY24.089</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,g</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions from manifolded group of compressor sources g, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Q
                                    <E T="52">s,g</E>
                                     = Volumetric gas emissions from manifolded group of compressor sources g, for reporting year, in standard cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i,g</E>
                                     = Mole fraction of GHG
                                    <E T="52">i</E>
                                     in the vent gas for measured manifolded group of compressor sources g; use the appropriate gas compositions in paragraph (u)(2) of this section.
                                </FP>
                            </EXTRACT>
                            <P>
                                (10) 
                                <E T="03">Method for calculating volumetric GHG emissions from reciprocating compressor venting at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility</E>
                                . You must calculate volumetric emissions from reciprocating compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility as specified in paragraphs (p)(10)(i) through (iv) of this section, as applicable.
                            </P>
                            <P>
                                (i) For all reciprocating compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility that are subject to the reciprocating compressor standards in § 60.5385b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you must conduct the volumetric emission measurements as required by § 60.5385b(b) and (c) of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, conduct any additional volumetric emission measurements specified in paragraph (p)(1) of this section using methods specified in paragraphs (p)(2) through (5) of this section (based on the compressor mode (as defined in 
                                <PRTPAGE P="42274"/>
                                § 98.238) in which the compressor was found at the time of measurement), and calculate emissions as specified in paragraphs (p)(6) through (9) of this section. Conduct all measurements required by this paragraph (p)(10)(i) at the frequency specified by § 60.5385b(a) of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter. For any reporting year in which measuring at the frequency specified by § 60.5385b(a) of this chapter results in measurement not being required for a subject compressor, calculate emissions for all mode-source combinations as specified in paragraph (p)(6)(ii) of this section.
                            </P>
                            <P>(ii) For all reciprocating compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility that are not subject to the reciprocating compressor standards in § 60.5385b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you may elect to conduct volumetric emission measurements specified in paragraph (p)(1) of this section using methods specified in paragraphs (p)(2) through (5) of this section (based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement), and calculate emissions as specified in paragraphs (p)(6) through (9) of this section.</P>
                            <P>(iii) For all reciprocating compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility for which paragraph (p)(10)(i) of this section does not apply, and you do not elect to conduct volumetric emission measurements specified in paragraph (p)(1) of this section, you must calculate total atmospheric rod packing emissions from all reciprocating compressors at either an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility using equation W-29D to this section. Reciprocating compressor rod packing emissions that are routed to a flare, combustion, or vapor recovery system are not required to be determined under this paragraph (p).</P>
                            <GPH SPAN="3" DEEP="43">
                                <GID>ER14MY24.090</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions from all reciprocating compressors, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">Count = Total number of reciprocating compressors with rod packing emissions vented directly to the atmosphere.</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,p</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions for reciprocating compressor p, at standard conditions, in cubic feet, calculated using equation W-29E to this section.
                                </FP>
                            </EXTRACT>
                            <P>(iv) For all reciprocating compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility for which paragraph (p)(10)(i) of this section does not apply, you must calculate rod packing vent emissions from each reciprocating compressor using equation W-29E to this section. Reciprocating compressor rod packing emissions that are routed to a flare, combustion, or vapor recovery system are not required to be determined under this paragraph (p).</P>
                            <GPH SPAN="3" DEEP="34">
                                <GID>ER14MY24.091</GID>
                            </GPH>
                            <FP SOURCE="FP-2">Where:</FP>
                            <EXTRACT>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i,p</E>
                                     = Annual volumetric GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) emissions for reciprocating compressor p, at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">s,p</E>
                                     = Emission factor for reciprocating compressor p, in standard cubic feet per year. Use 2.13 × 10
                                    <SU>5</SU>
                                     standard cubic feet per year per compressor for CH
                                    <E T="52">4</E>
                                     and 1.18 × 10
                                    <SU>4</SU>
                                     standard cubic feet per year per compressor for CO
                                    <E T="52">2</E>
                                     at 60 °F and 14.7 psia.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">p</E>
                                     = Total time reciprocating compressor p was in operating mode, for which E
                                    <E T="52">s,i,p</E>
                                    , is being calculated in the reporting year, in hours.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">total</E>
                                     = Total hours per year. Use 8784 in leap years and use 8760 in all other years.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i,p</E>
                                     = Mole fraction of GHG (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) in the vent gas for reciprocating compressor p in operating mode; use the appropriate gas compositions in paragraph (u)(2) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">EF</E>
                                     = Mole fraction of GHG (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) used in the determination of EF
                                    <E T="52">s,p</E>
                                    . Use 0.98 for CH
                                    <E T="52">4</E>
                                     and 0.02 for CO
                                    <E T="52">2</E>
                                    .
                                </FP>
                            </EXTRACT>
                            <P>
                                (11) 
                                <E T="03">Method for converting from volumetric to mass emissions.</E>
                                 You must calculate both CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.
                            </P>
                            <P>
                                (q) 
                                <E T="03">Equipment leak surveys.</E>
                                 For the components identified in paragraphs (q)(1)(i) through (iii) and (v) of this section, you must conduct equipment leak surveys using the leak detection methods specified in paragraphs (q)(1)(i) through (iii) and (v) of this section. For the components identified in paragraph (q)(1)(iv) and (vi) of this section, you may elect to conduct equipment leak surveys, and if you elect to conduct surveys, you must use a leak detection method specified in paragraph (q)(1)(iv) and (vi) of this section. This paragraph (q) applies to components in streams with gas content greater than 10 percent CH
                                <E T="52">4</E>
                                 plus CO
                                <E T="52">2</E>
                                 by weight. Components in streams with gas content less than or equal to 10 percent CH
                                <E T="52">4</E>
                                 plus CO
                                <E T="52">2</E>
                                 by weight are exempt from the requirements of this paragraph (q) and do not need to be reported. Tubing systems equal to or less than one half inch diameter are exempt from the requirements of this paragraph (q) and do not need to be reported. Equipment leak components in vacuum service are exempt from the survey and emission estimation requirements of this paragraph (q) and only the count of these equipment must be reported.
                            </P>
                            <P>
                                (1) 
                                <E T="03">Survey requirements</E>
                                —(i) For the components listed in § 98.232(e)(7), (f)(5), (g)(4), and (h)(5), that are not subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or 60.5398b of this chapter, or an applicable approved state plan or 
                                <PRTPAGE P="42275"/>
                                applicable Federal plan in part 62 of this chapter, you must conduct surveys using any of the leak detection methods listed in § 98.234(a) and calculate equipment leak emissions using the procedures specified in either paragraph (q)(2) or (3) of this section.
                            </P>
                            <P>(ii) For the components listed in § 98.232(i)(1), you must conduct surveys using any of the leak detection methods listed in § 98.234(a) except § 98.234(a)(2)(ii) and calculate equipment leak emissions using the procedures specified in either paragraph (q)(2) or (3) of this section.</P>
                            <P>(iii) For the components listed in § 98.232(c)(21)(i), (e)(7) and (8), (f)(5) through (8), (g)(4), (g)(6) and (7), (h)(5), (h)(7) and (8), and (j)(10)(i) that are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, and are required to conduct surveys using any of the leak detection methods in § 98.234(a)(1)(ii) or (iii) or (a)(2)(ii), as applicable, you must use the results of those surveys to calculate equipment leak emissions using the procedures specified in either paragraph (q)(2) or (3) of this section.</P>
                            <P>(iv) For the components listed in § 98.232(c)(21)(i), (e)(8), (f)(6) through (8), (g)(6) or (7), (h)(7) or (8), or (j)(10)(i), that are not subject to or are not required to conduct surveys using the methods in § 98.234(a) in accordance with the fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you may elect to conduct surveys according to this paragraph (q), and, if you elect to do so, then you must use one of the leak detection methods in § 98.234(a).</P>
                            <P>(A) If you elect to use a leak detection method in § 98.234(a) for the surveyed component types in § 98.232(c)(21)(i), (f)(7), (g)(6), (h)(7), or (j)(10)(i) in lieu of the population count methodology specified in paragraph (r) of this section, then you must calculate emissions for the surveyed component types in § 98.232(c)(21)(i), (f)(7), (g)(6), (h)(7), or (j)(10)(i) using the procedures in either paragraph (q)(2) or (3) of this section.</P>
                            <P>(B) If you elect to use a leak detection method in § 98.234(a) for the surveyed component types in § 98.232(e)(8), (f)(6) and (8), (g)(7), and (h)(8), then you must use the procedures in either paragraph (q)(2) or (3) of this section to calculate those emissions.</P>
                            <P>(C) If you elect to use a leak detection method in § 98.234(a)(1)(ii) or (iii) or (a)(2)(ii), as applicable, for any elective survey under paragraph (q)(1)(iv) of this section, then you must survey the component types in § 98.232(c)(21)(i), (e)(8), (f)(6) through (8), (g)(6) and (7), (h)(7) and (8), and (j)(10)(i) that are not subject to or are not required to conduct surveys using the methods in § 98.234(a) in accordance with the fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, and you must calculate emissions from the surveyed component types in § 98.232(c)(21)(i), (e)(8), (f)(6) through (8), (g)(6) and (7), (h)(7) and (8), and (j)(10)(i) using the emission calculation requirements in either paragraph (q)(2) or (3) of this section.</P>
                            <P>(v) For the components listed in § 98.232(d)(7), you must conduct surveys as specified in paragraphs (q)(1)(v)(A) and (B) of this section and you must calculate equipment leak emissions using the procedures specified in either paragraph (q)(2) or (3) of this section.</P>
                            <P>(A) For the components listed in § 98.232(d)(7) that are not subject to the equipment leak standards for onshore natural gas processing plants in § 60.5400b or § 60.5401b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you may use any of the leak detection methods listed in § 98.234(a).</P>
                            <P>(B) For the components listed in § 98.232(d)(7) that are subject to the equipment leak standards for onshore natural gas processing plants in § 60.5400b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you must use either of the leak detection methods in § 98.234(a)(1)(iii) or (a)(2)(ii).</P>
                            <P>(vi) For the components listed in § 98.232(m)(3)(ii) and (m)(4)(ii), you may elect to conduct surveys according to this paragraph (q), and, if you elect to do so, then you must use one of the leak detection methods in § 98.234(a). If you elect to use a leak detection method in § 98.234(a) for the surveyed component types in § 98.232(m)(3)(ii) and (m)(4)(ii) in lieu of the population count methodology specified in paragraph (r) of this section, then you must calculate emissions for the surveyed component types in § 98.232(m)(3)(ii) and (m)(4)(ii) using the procedures in either paragraph (q)(2) or (3) of this section.</P>
                            <P>(vii) Except as provided in paragraph (q)(1)(viii) of this section, you must conduct at least one complete leak detection survey in a calendar year. If you conduct multiple complete leak detection surveys in a calendar year, you must use the results from each complete leak detection survey when calculating emissions using the procedures specified in either paragraph (q)(2) or (3) of this section. Except as provided in paragraphs (q)(1)(vii)(A) through (H) of this section, a complete leak detection survey is a survey in which all equipment components required to be surveyed as specified in paragraphs (q)(1)(i) through (vi) of this section are surveyed.</P>
                            <P>(A) For components subject to the well site and compressor station fugitive emissions standards in § 60.5397a of this chapter, each survey conducted in accordance with § 60.5397a of this chapter using one of the methods in § 98.234(a) will be considered a complete leak detection survey for purposes of this section.</P>
                            <P>(B) For components subject to the well site, centralized production facility, and compressor station fugitive emissions standards in § 60.5397b or 60.5398b of this chapter, each survey conducted in accordance with the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b, 60.5398b(b)(4) or 60.5398b(b)(5)(ii) of this chapter using one of the methods in § 98.234(a) will be considered a complete leak detection survey for purposes of this section.</P>
                            <P>(C) For components subject to the well site, centralized production facility, and compressor station fugitive emissions standards in an applicable approved state plan or applicable Federal plan in part 62 of this chapter, each survey conducted in accordance with the applicable approved state plan or applicable Federal plan in part 62 of this chapter using one of the methods in § 98.234(a) will be considered a complete leak detection survey for purposes of this section.</P>
                            <P>
                                (D) For an onshore petroleum and natural gas production facility electing to conduct leak detection surveys according to paragraph (q)(1)(iv) of this section, a survey of all required components at a single well-pad will be considered a complete leak detection survey for purposes of this section.
                                <PRTPAGE P="42276"/>
                            </P>
                            <P>(E) For an onshore petroleum and natural gas gathering and boosting facility electing to conduct leak detection surveys according to paragraph (q)(1)(iv) of this section, a survey of all required components at a gathering and boosting site, as defined in § 98.238, will be considered a complete leak detection survey for purposes of this section.</P>
                            <P>(F) For an onshore natural gas processing facility subject to the equipment leak standards for onshore natural gas processing plants in § 60.5400b or § 60.5401b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, each survey conducted in accordance with the equipment leak standards for onshore natural gas processing plants in § 60.5400b or § 60.5401b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter will be considered a complete leak detection survey for the purposes of calculating emissions using the procedures specified in either paragraph (q)(2) or (3) of this section. At least one complete leak detection survey conducted during the reporting year must include all components listed in § 98.232(d)(7) and subject to this paragraph (q), including components which are considered difficult-to-monitor emission sources as specified in § 98.234(a). Inaccessible components as provided in §§ 60.5401b(h)(3) and 60.5401c(h)(3) of this chapter are exempt from the monitoring requirements in this subpart.</P>
                            <P>(G) For natural gas distribution facilities that choose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years as provided in paragraph (q)(1)(vii) of this section, a survey of all required components at the above grade transmission-distribution transfer stations monitored during the calendar year will be considered a complete leak detection survey for purposes of this section.</P>
                            <P>(H) For onshore natural gas transmission pipeline facilities that conduct leak detection surveys according to paragraph (q)(1)(vi) of this section, a survey of all required components at a transmission company interconnect metering-regulating station or a farm tap/direct sale metering-regulating station, will be considered a complete leak detection survey for purposes of this section.</P>
                            <P>(viii) Natural gas distribution facilities are required to perform equipment leak surveys only at above grade stations that qualify as transmission-distribution transfer stations. Below grade transmission-distribution transfer stations and all metering-regulating stations that do not meet the definition of transmission-distribution transfer stations are not required to perform equipment leak surveys under this section. Natural gas distribution facilities may choose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years “n,” not exceeding a five-year period to cover all above grade transmission-distribution transfer stations. If the facility chooses to use the multiple year option, then the number of transmission-distribution transfer stations that are monitored in each year should be approximately equal across all years in the cycle.</P>
                            <P>
                                (2) 
                                <E T="03">Calculation Method 1: Leaker emission factor calculation methodology.</E>
                                 If you elect not to measure leaks according to Calculation Method 2 as specified in paragraph (q)(3) of this section, you must use this Calculation Method 1 for all components included in a complete leak survey. For industry segments listed in § 98.230(a)(2) through (10), if equipment leaks are detected during surveys required or elected for components listed in paragraphs (q)(1)(i) through (vi) of this section, then you must calculate equipment leak emissions per component type per reporting facility, well-pad site, or gathering and boosting site, as applicable, using equation W-30 to this section and the requirements specified in paragraphs (q)(2)(i) through (x) and (xii) of this section. For the industry segment listed in § 98.230(a)(8), the results from equation W-30 to this section are used to calculate population emission factors on a meter/regulator run basis using equation W-31 to this section. If you chose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years, “n,” according to paragraph (q)(1)(viii) of this section, then you must calculate the emissions from all above grade transmission-distribution transfer stations as specified in paragraph (q)(2)(xi) of this section.
                            </P>
                            <GPH SPAN="3" DEEP="44">
                                <GID>ER14MY24.092</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,p,i</E>
                                     = Annual total volumetric emissions of GHG
                                    <E T="52">i</E>
                                     from specific component type “p” (in accordance with paragraphs (q)(1)(i) through (vi) of this section) in standard (“s”) cubic feet, as specified in paragraphs (q)(2)(ii) through (x) and (xii) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    x
                                    <E T="52">p</E>
                                     = Total number of specific component type “p” detected as leaking in any leak survey during the year. A component found leaking in two or more surveys during the year is counted as one leaking component.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">s,p</E>
                                     = Leaker emission factor as specified in paragraphs (q)(2)(iii) through (x) and (xii) of this section.
                                </FP>
                                <FP SOURCE="FP-2">k = Factor to adjust for undetected leaks by respective leak detection method, where k equals 1.25 for the methods in § 98.234(q)(1), (3) and (5); k equals 1.55 for the method in § 98.234(q)(2)(i); and k equals 1.27 for the method in § 98.234(q)(2)(ii).</FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i</E>
                                     = For onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities, concentration of GHG
                                    <E T="52">i</E>
                                    , CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    , in produced natural gas as defined in paragraph (u)(2) of this section; for onshore natural gas processing facilities, concentration of GHG
                                    <E T="52">i</E>
                                    , CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    , in the total hydrocarbon of the feed natural gas; for onshore natural gas transmission compression and underground natural gas storage, GHG
                                    <E T="52">i</E>
                                     equals 0.975 for CH
                                    <E T="52">4</E>
                                     and 1.1 × 10
                                    <E T="51">−2</E>
                                     for CO
                                    <E T="52">2</E>
                                     or concentration of GHG
                                    <E T="52">i</E>
                                    , CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    , in the total hydrocarbon of the feed natural gas; for LNG storage and LNG import and export equipment and onshore natural gas transmission pipeline, GHG
                                    <E T="52">i</E>
                                     equals 1 for CH
                                    <E T="52">4</E>
                                     and 0 for CO
                                    <E T="52">2</E>
                                    ; and for natural gas distribution, GHG
                                    <E T="52">i</E>
                                     equals 1 for CH
                                    <E T="52">4</E>
                                     and 1.1 × 10
                                    <E T="51">−2</E>
                                     for CO
                                    <E T="52">2</E>
                                    .
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">p,z</E>
                                     = The total time the surveyed component “z,” component type “p,” was assumed to be leaking and operational, in hours. If one leak detection survey is conducted in the calendar year, assume the component was leaking for the entire calendar year. If multiple leak detection surveys are conducted in the calendar year, assume a component found leaking in the first survey was leaking since the beginning of the year until the date of the survey; assume a component found leaking in the last survey of the year was leaking from the preceding survey through the end of the year; assume a component found leaking in a survey between the first and last surveys of the 
                                    <PRTPAGE P="42277"/>
                                    year was leaking since the preceding survey until the date of the survey; and sum times for all leaking periods. For each leaking component, account for time the component was not operational (
                                    <E T="03">i.e.,</E>
                                     not operating under pressure) using an engineering estimate based on best available data.
                                </FP>
                            </EXTRACT>
                            <P>(i) The leak detection surveys selected for use in equation W-30 to this section must be conducted during the calendar year as indicated in paragraph (q)(1)(vii) and (viii) of this section, as applicable.</P>
                            <P>
                                (ii) Calculate both CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 mass emissions using calculations in paragraph (v) of this section.
                            </P>
                            <P>(iii) Onshore petroleum and natural gas production facilities must, if available, use the facility-specific leaker emission factor calculated in accordance with paragraph (q)(4) of section or use the appropriate default whole gas leaker emission factors consistent with the well type, where components associated with gas wells are considered to be in gas service and components associated with oil wells are considered to be in oil service as listed in table W-2 to this subpart.</P>
                            <P>(iv) Onshore petroleum and natural gas gathering and boosting facilities must, if available, use the facility-specific leaker emission factor calculated in accordance with paragraph (q)(4) of section or use the appropriate default whole gas leaker factors for components in gas service listed in table W-2 to this subpart.</P>
                            <P>(v) Onshore natural gas processing facilities must, if available, use the facility-specific leaker emission factor calculated in accordance with paragraph (q)(4) of section or use the appropriate default total hydrocarbon leaker emission factors for compressor components in gas service and non-compressor components in gas service listed in table W-4 to this subpart.</P>
                            <P>(vi) Onshore natural gas transmission compression facilities must, if available, use the facility-specific leaker emission factor calculated in accordance with paragraph (q)(4) of section or use the appropriate default total hydrocarbon leaker emission factors for compressor components in gas service and non-compressor components in gas service listed in table W-4 to this subpart.</P>
                            <P>(vii) Underground natural gas storage facilities must, if available, use the facility-specific leaker emission factor calculated in accordance with paragraph (q)(4) of section or use the appropriate default total hydrocarbon leaker emission factors for storage stations or storage wellheads in gas service listed in table W-4 to this subpart.</P>
                            <P>(viii) LNG storage facilities must, if available, use the facility-specific leaker emission factor calculated in accordance with paragraph (q)(4) of section or use the appropriate default methane leaker emission factors for LNG storage components in LNG service or gas service listed in table W-6 to this subpart.</P>
                            <P>(ix) LNG import and export facilities must, if available, use the facility-specific leaker emission factor calculated in accordance with paragraph (q)(4) of section or use the appropriate default methane leaker emission factors for LNG terminals components in LNG service or gas service listed in table W-6 to this subpart.</P>
                            <P>(x) Except as provided in paragraph (q)(3)(viii) of this section, natural gas distribution facilities must use equation W-30 to this section and the default methane leaker emission factors for transmission-distribution transfer station components in gas service listed in table W-6 to this subpart to calculate component emissions from annual equipment leak surveys conducted at above grade transmission-distribution transfer stations.</P>
                            <P>
                                (A) Use equation W-31 to this section to determine the meter/regulator run population emission factors for each GHG
                                <E T="52">i</E>
                                . As additional survey data become available, you must recalculate the meter/regulator run population emission factors for each GHG
                                <E T="52">i</E>
                                 annually according to paragraph (q)(2)(x)(B) of this section.
                            </P>
                            <GPH SPAN="3" DEEP="69">
                                <GID>ER14MY24.093</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">s,MR,i</E>
                                     = Meter/regulator run population emission factor for GHG
                                    <E T="52">i</E>
                                     based on all surveyed above grade transmission-distribution transfer stations over “n” years, in standard cubic feet of GHG
                                    <E T="52">i</E>
                                     per operational hour of all meter/regulator runs.
                                </FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,p,i,y</E>
                                     = Annual total volumetric emissions at standard conditions of GHG
                                    <E T="52">i</E>
                                     from component type “p” during year “y” in standard (“s”) cubic feet, as calculated using equation W-30 to this section.
                                </FP>
                                <FP SOURCE="FP-2">p = Seven component types listed in table W-6 to this subpart for transmission-distribution transfer stations.</FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">w,y</E>
                                     = The total time the surveyed meter/regulator run “w” was operational, in hours during survey year “y” using an engineering estimate based on best available data.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Count
                                    <E T="52">MR,y</E>
                                     = Count of meter/regulator runs surveyed at above grade transmission-distribution transfer stations in year “y”.
                                </FP>
                                <FP SOURCE="FP-2">
                                    y = Year of data included in emission factor “EF
                                    <E T="52">s,MR,i</E>
                                    ” according to paragraph (q)(2)(x)(B) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    n = Number of years of data, according to paragraph (q)(1)(vii) of this section, whose results are used to calculate emission factor “EF
                                    <E T="52">s,MR,i</E>
                                    ” according to paragraph (q)(2)(x)(B) of this section.
                                </FP>
                            </EXTRACT>
                            <P>
                                (B) The emission factor “EF
                                <E T="52">s,MR,i</E>
                                ,” based on annual equipment leak surveys at above grade transmission-distribution transfer stations, must be calculated annually. If you chose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years, “n,” according to paragraph (q)(1)(viii) of this section and you have submitted a smaller number of annual reports than the duration of the selected cycle period of 5 years or less, then all available data from the current year and previous years must be used in the calculation of the emission factor “EF
                                <E T="52">s,MR,i</E>
                                ” from equation W-31 to this section. After the first survey cycle of “n” years is completed and beginning in calendar year (n+1), the survey will continue on a rolling basis by including the survey results from the current calendar year “y” and survey results from all previous (n−1) calendar years, such that each annual calculation of the emission factor “EF
                                <E T="52">s,MR,i</E>
                                ” from equation W-31 to this section is based on survey results from “n” years. Upon completion of a cycle, you may elect to change the number of years in the next cycle period (to be 5 years or less). If the number of years in the new cycle is greater than the number of years in the previous cycle, calculate “EF
                                <E T="52">s,MR,i</E>
                                ” from equation W-31 to this section in each year of the new cycle using the survey results from the current calendar year and the survey results 
                                <PRTPAGE P="42278"/>
                                from the preceding number years that is equal to the number of years in the previous cycle period. If the number of years, “n
                                <E T="52">new</E>
                                ,” in the new cycle is smaller than the number of years in the previous cycle, “n,” calculate “EF
                                <E T="52">s,MR,i</E>
                                ” from equation W-31 to this section in each year of the new cycle using the survey results from the current calendar year and survey results from all previous (n
                                <E T="52">new</E>
                                −1) calendar years.
                            </P>
                            <P>(xi) If you chose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years, “n,” according to paragraph (q)(1)(viii) of this section, you must use the meter/regulator run population emission factors calculated using equation W-31 to this section and the total count of all meter/regulator runs at above grade transmission-distribution transfer stations to calculate emissions from all above grade transmission-distribution transfer stations using equation W-32B to this section.</P>
                            <P>(xii) Onshore natural gas transmission pipeline facilities must use the facility-specific leaker emission factor calculated in accordance with paragraph (q)(4) of this section.</P>
                            <P>
                                (3) 
                                <E T="03">Calculation Method 2: Leaker measurement methodology.</E>
                                 For industry segments listed in § 98.230(a)(2) through (10), if equipment leaks are detected during surveys required or elected for components listed in paragraphs (q)(1)(i) through (vi) of this section, you may elect to measure the volumetric flow rate of each natural gas leak identified during a complete leak survey. If you elect to use this method, you must use this method for all components included in a complete leak survey and you must determine the volumetric flow rate of each natural gas leak identified during the leak survey and aggregate the emissions by the method of leak detection and component type as specified in paragraphs (q)(3)(i) through (vii) of this section.
                            </P>
                            <P>(i) Determine the volumetric flow rate of each natural gas leak identified during the leak survey following the methods § 98.234(b) through (d), as appropriate for each leak identified. You do not need to use the same measurement method for each leak measured. If you are unable to measure the natural gas leak because it would require elevating the measurement personnel more than 2 meters above the surface and a lift is unavailable at the site or it would pose immediate danger to measurement personnel, then you must substitute the default leak rate for the component and site type from tables W-2, W-4, or W-6 to this subpart, as applicable, as the measurement for this leak.</P>
                            <P>
                                (ii) For each leak, calculate the volume of natural gas emitted as the product of the natural gas flow rate measured in paragraph (q)(3)(i) of this section and the duration of the leak. If one leak detection survey is conducted in the calendar year, assume the component was leaking for the entire calendar year. If multiple leak detection surveys are conducted in the calendar year, assume a component found leaking in the first survey was leaking since the beginning of the year until the date of the survey; assume a component found leaking in the last survey of the year was leaking from the preceding survey through the end of the year; assume a component found leaking in a survey between the first and last surveys of the year was leaking since the preceding survey until the date of the survey. For each leaking component, account for time the component was not operational (
                                <E T="03">i.e.</E>
                                , not operating under pressure) using an engineering estimate based on best available data.
                            </P>
                            <P>(iii) For each leak, convert the volumetric emissions of natural gas determined in paragraph (q)(3)(ii) of this section to standard conditions using the method specified in paragraph (t)(1) of this section.</P>
                            <P>
                                (iv) For each leak, convert the volumetric emissions of natural gas at standard conditions determined in paragraph (q)(3)(iii) of this section to CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 volumetric emissions at standard conditions using the methods specified in paragraph (u) of this section.
                            </P>
                            <P>(v) For each leak, convert the GHG volumetric emissions at standard conditions determined in paragraph (q)(3)(iv) of this section to GHG mass emissions using the methods specified in paragraph (v) of this section.</P>
                            <P>
                                (vi) Sum the CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 mass emissions determined in paragraph (q)(3)(v) of this section separately for each type of component required to be surveyed by the method used for the survey for which a leak was detected.
                            </P>
                            <P>
                                (vii) Multiply the total CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 mass emissions by survey method and component type determined in paragraph (q)(3)(vi) by the survey specific value for “k”, the factor adjustment for undetected leaks, where k equals 1.25 for the methods in § 98.234(q)(1), (3) and (5); k equals 1.55 for the method in § 98.234(q)(2)(i); and k equals 1.27 for the method in § 98.234(q)(2)(ii).
                            </P>
                            <P>(viii) For natural gas distribution facilities:</P>
                            <P>
                                (A) Use equation W-31 to this section to determine the meter/regulator run population emission factors for each GHG
                                <E T="52">i</E>
                                 using the methods as specified in paragraphs (q)(2)(x)(A) and (B) of this section, except use the sum of the GHG volumetric emissions for each type of component required to be surveyed by the method used for the survey for which a leak was detected calculated in paragraph (q)(3)(iv) of this section rather than the emissions calculated using equation W-30 to this section.
                            </P>
                            <P>(B) If you chose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years, “n,” according to paragraph (q)(1)(vii) of this section, you must use the meter/regulator run population emission factors calculated according to paragraph (q)(3)(vii)(A) of this section and the total count of all meter/regulator runs at above grade transmission-distribution transfer stations to calculate emissions from all above grade transmission-distribution transfer stations using equation W-32B to this section.</P>
                            <P>
                                (4) 
                                <E T="03">Development of facility-specific component-level leaker emission factors by leak detection method.</E>
                                 If you elect to measure leaks according to Calculation Method 2 as specified in paragraph (q)(3) of this section, you must use the measurement values determined in accordance with paragraph (q)(3) of this section to calculate a facility-specific component-level leaker emission factor by leak detection method as provided in paragraphs (q)(4)(i) through (iv) of this section.
                            </P>
                            <P>(i) You must track the leak measurements made separately for each of the applicable components listed in paragraphs (q)(1)(i) through (v) of this section and by the leak detection method according to the following three bins.</P>
                            <P>(A) Method 21 as specified in § 98.234(a)(2)(i).</P>
                            <P>(B) Method 21 as specified in § 98.234(a)(2)(ii).</P>
                            <P>(C) Optical gas imaging (OGI) and other leak detection methods as specified in § 98.234(a)(1), (3), or (5).</P>
                            <P>(ii) You must accumulate a minimum of 50 leak measurements total for a given component type and leak detection method combination before you can develop and use a facility-specific component-level leaker emission factor for use in calculating emissions according to paragraph (q)(2) of this section (Calculation Method 1: Leaker emission factor calculation methodology).</P>
                            <P>
                                (iii) Sum the volumetric flow rate of natural gas determined in accordance with paragraph (q)(3)(i) of this section for each leak by component type and 
                                <PRTPAGE P="42279"/>
                                leak detection method as specified in paragraph (q)(4)(i) of this section meeting the minimum number of measurement requirement in paragraph (q)(4)(ii) of this section.
                            </P>
                            <P>(iv) Convert the volumetric flow rate of natural gas determined in paragraph (q)(4)(iii) of this section to standard conditions using the method specified in paragraph (t)(1) of this section.</P>
                            <P>(v) Determine the emission factor in units of standard cubic feet per hour component (scf/hr-component) by dividing the sum of the volumetric flow rate of natural gas determined in paragraph (q)(4)(iv) of this section by the total number of leak measurements for that component type and leak detection method combination.</P>
                            <P>(vi) You must update the emission factor determined in (q)(4)(v) of this section annually to include the results from all complete leak surveys for which leak measurement was performed during the reporting year in accordance with paragraph (q)(3) of this section.</P>
                            <P>
                                (r) 
                                <E T="03">Equipment leaks by population count.</E>
                                 This paragraph (r) applies to emissions sources listed in § 98.232(c)(21)(ii), (f)(7), (g)(5), (h)(6), (j)(10)(ii), (m)(3)(i), and (m)(4)(i) if you are not required to comply with paragraph (q) of this section and if you do not elect to comply with paragraph (q) of this section for these components in lieu of this paragraph (r). This paragraph (r) also applies to emission sources listed in § 98.232(i)(2) through (6), (j)(11), and (m)(5). To be subject to the requirements of this paragraph (r), the listed emissions sources also must contact streams with gas content greater than 10 percent CH
                                <E T="52">4</E>
                                 plus CO
                                <E T="52">2</E>
                                 by weight. Emissions sources that contact streams with gas content less than or equal to 10 percent CH
                                <E T="52">4</E>
                                 plus CO
                                <E T="52">2</E>
                                 by weight are exempt from the requirements of this paragraph (r) and do not need to be reported. Tubing systems equal to or less than one half inch diameter are exempt from the requirements of this paragraph (r) and do not need to be reported. Equipment leak components in vacuum service are exempt from the survey and emission estimation requirements of this paragraph (r) and only the count of these equipment must be reported. You must calculate emissions from all emission sources listed in this paragraph (r) using equation W-32A to this section, except for natural gas distribution facility emission sources listed in § 98.232(i)(3). Natural gas distribution facility emission sources listed in § 98.232(i)(3) must calculate emissions using equation W-32B to this section and according to paragraph (r)(6)(ii) of this section.
                            </P>
                            <GPH SPAN="3" DEEP="14">
                                <GID>ER14MY24.094</GID>
                            </GPH>
                            <GPH SPAN="3" DEEP="15">
                                <GID>ER14MY24.095</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,e,i</E>
                                     = Annual volumetric emissions of GHG
                                    <E T="52">i</E>
                                     from the emission source type in standard cubic feet. The emission source type may be a major equipment (
                                    <E T="03">e.g.,</E>
                                     wellhead, separator), component (
                                    <E T="03">e.g.,</E>
                                     connector, open-ended line), below grade metering-regulating station, below grade transmission-distribution transfer station, distribution main, distribution service, gathering pipeline, transmission company interconnect metering-regulating station, farm tap and/or direct sale metering-regulating station, or transmission pipeline.
                                </FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,MR,i</E>
                                     = Annual volumetric emissions of GHG
                                    <E T="52">i</E>
                                     from all meter/regulator runs at above grade metering regulating stations that are not above grade transmission-distribution transfer stations or, when used to calculate emissions according to paragraph (q)(2)(xi) or (q)(3)(vii)(B) of this section, the annual volumetric emissions of GHG
                                    <E T="52">i</E>
                                     from all meter/regulator runs at above grade transmission-distribution transfer stations.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Count
                                    <E T="52">e</E>
                                     = Total number of the emission source type at the facility. Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must count each major equipment piece listed in table W-1 to this subpart. Onshore petroleum and natural gas gathering and boosting facilities must also count the miles of gathering pipelines by material type (protected steel, unprotected steel, plastic, or cast iron). Underground natural gas storage facilities must count each component listed in table W-3 to this subpart. LNG storage facilities must count the number of vapor recovery compressors. LNG import and export facilities must count the number of vapor recovery compressors. Natural gas distribution facilities must count the: (1) Number of distribution services by material type; (2) miles of distribution mains by material type; (3) number of below grade transmission-distribution transfer stations; and (4) number of below grade metering-regulating stations; as listed in table W-5 to this subpart. Onshore natural gas transmission pipeline facilities must count the following, as listed in table W-5 to this subpart: (1) Miles of transmission pipelines by material type; (2) number of transmission company interconnect metering-regulating stations; and (3) number of farm tap and/or direct sale metering-regulating stations.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Count
                                    <E T="52">MR</E>
                                     = Total number of meter/regulator runs at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations or, when used to calculate emissions according to paragraph (q)(2)(xi) or (q)(3)(vii)(B) of this section, the total number of meter/regulator runs at above grade transmission-distribution transfer stations.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">s,e</E>
                                     = Population emission factor for the specific emission source type, as specified in paragraphs (r)(2) through (7) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">s,MR,i</E>
                                     = Meter/regulator run population emission factor for GHG
                                    <E T="52">i</E>
                                     based on all surveyed above grade transmission-distribution transfer stations over “n” years, in standard cubic feet of GHG
                                    <E T="52">i</E>
                                     per operational hour of all meter/regulator runs, as determined in equation W-31 to this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">i</E>
                                     = For onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities, concentration of GHG
                                    <E T="52">i</E>
                                    , CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    , in produced natural gas as defined in paragraph (u)(2) of this section; for onshore natural gas transmission compression and underground natural gas storage, GHG
                                    <E T="52">i</E>
                                     equals 0.975 for CH
                                    <E T="52">4</E>
                                     and 1.1 × 10
                                    <E T="51">−2</E>
                                     for CO
                                    <E T="52">2</E>
                                     or concentration of GHG
                                    <E T="52">i</E>
                                    , CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    , in the total hydrocarbon of the feed natural gas; for LNG storage and LNG import and export equipment, GHG
                                    <E T="52">i</E>
                                     equals 1 for CH
                                    <E T="52">4</E>
                                     and 0 for CO
                                    <E T="52">2</E>
                                    ; and for natural gas distribution and onshore natural gas transmission pipeline, GHG
                                    <E T="52">i</E>
                                     equals 1 for CH
                                    <E T="52">4</E>
                                     and 1.1 × 10
                                    <E T="51">−2</E>
                                     CO
                                    <E T="52">2</E>
                                    .
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">e</E>
                                     = Average estimated time that each emission source type associated with the equipment leak emission was operational in the calendar year, in hours, using engineering estimate based on best available data.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">w,avg</E>
                                     = Average estimated time that each meter/regulator run was operational in the calendar year, in hours per meter/regulator run, using engineering estimate based on best available data.
                                </FP>
                            </EXTRACT>
                            <P>
                                (1) Calculate both CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.
                            </P>
                            <P>
                                (2) Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and 
                                <PRTPAGE P="42280"/>
                                boosting facilities must use the appropriate default whole gas population emission factors listed in table W-1 to this subpart. Major equipment associated with gas wells are considered gas service equipment in table W-1 to this subpart. Onshore petroleum and natural gas gathering and boosting facilities shall use the gas service equipment emission factors in table W-1 to this subpart. Major equipment associated with crude oil wells are considered crude service equipment in table W-1 to this subpart. Where facilities conduct EOR operations, the emission factor listed in table W-1 to this subpart shall be used to estimate all streams of gases, including recycle CO
                                <E T="52">2</E>
                                 stream. For meters/piping, use one meters/piping per well-pad for onshore petroleum and natural gas production operations and the number of meters in the facility for onshore petroleum and natural gas gathering and boosting operations.
                            </P>
                            <P>(3) Underground natural gas storage facilities must use the appropriate default total hydrocarbon population emission factors for storage wellheads in gas service listed in table W-3 to this subpart.</P>
                            <P>(4) LNG storage facilities must use the appropriate default methane population emission factors for LNG storage compressors in gas service listed in table W-5 to this subpart.</P>
                            <P>(5) LNG import and export facilities must use the appropriate default methane population emission factors for LNG terminal compressors in gas service listed in table W-5 to this subpart.</P>
                            <P>(6) Natural gas distribution facilities must use the appropriate methane emission factors as described in paragraphs (r)(6)(i) and (ii) of this section.</P>
                            <P>(i) Below grade transmission-distribution transfer stations, below grade metering-regulating stations, distribution mains, and distribution services must use the appropriate default methane population emission factors listed in table W-5 to this subpart to estimate emissions from components listed in § 98.232(i)(2), (4), (5), and (6), respectively.</P>
                            <P>(ii) Above grade metering-regulating stations that are not above grade transmission-distribution transfer stations must use the meter/regulator run population emission factor calculated in equation W-31 to this section in accordance with paragraph (q)(2)(x) or (q)(3)(viii)(A) of this section for the components listed in § 98.232(i)(3). Natural gas distribution facilities that do not have above grade transmission-distribution transfer stations are not required to calculate emissions for above grade metering-regulating stations and are not required to report GHG emissions in § 98.236(r)(2)(v).</P>
                            <P>(7) Onshore natural gas transmission pipeline facilities must use the appropriate default methane population emission factors listed in table W-5 to this subpart to estimate emissions from components listed in § 98.232(m)(3)(i), (4)(i) and (5).</P>
                            <P>
                                (s) 
                                <E T="03">Offshore petroleum and natural gas production facilities</E>
                                . Calculate CO
                                <E T="52">2</E>
                                , CH
                                <E T="52">4</E>
                                , and N
                                <E T="52">2</E>
                                O emissions for offshore petroleum and natural gas production from all equipment leaks (
                                <E T="03">i.e.,</E>
                                 fugitives), vented emission, and flare emission source types as identified by BOEM in the most recent monitoring and calculation methods published by BOEM referenced in 30 CFR 550.302 through 304.
                            </P>
                            <P>(1) Offshore production facilities that report to BOEM's emissions inventory must calculate emissions as specified in paragraph (s)(1)(i) or (ii) of this section, as applicable.</P>
                            <P>(i) Report the same annual emissions calculated using the most recent monitoring and calculation methods published by BOEM as referenced in 30 CFR 550.302 through 304 for any reporting year that overlaps with a BOEM emissions inventory year and any other reporting year in which the BOEM's emissions reporting system is available and the facility has the data needed to use BOEM's emissions reporting system.</P>
                            <P>(ii) If BOEM's emissions reporting system is not available or if the facility does not have the data needed to use BOEM's emissions reporting system, adjust emissions from the most recent emissions calculated in accordance with paragraph (s)(1)(i), (s)(3), or (s)(4) of this section, as applicable, by using a ratio of the operating time for the facility in the current reporting year relative to the operating time for the facility during the reporting year for which emissions were calculated as specified in paragraph (s)(1)(i), (s)(3), or (s)(4) of this section, as applicable.</P>
                            <P>(2) Offshore production facilities that do not report to BOEM's emissions inventory must calculate emissions as specified in paragraph (s)(2)(i) or (ii) of this section, as applicable.</P>
                            <P>(i) Use the most recent monitoring and calculation methods published by BOEM as referenced in 30 CFR 550.302 through 304 to calculate and report annual emissions for any reporting year that overlaps with a BOEM emissions inventory year and any other reporting year in which the facility has the data needed to use BOEM's emissions calculation methods.</P>
                            <P>(ii) If the facility does not have the data needed to use BOEM's calculation methods, adjust emissions from the facility's most recent emissions calculated in accordance with paragraph (s)(2)(i), (s)(3), or (s)(4) of this section, as applicable, by using a ratio of the operating time for the facility in the current reporting year relative to the operating time for the facility in the reporting year for which the emissions were calculated as specified in paragraph (s)(2)(i), (s)(3), or (s)(4) of this section, as applicable.</P>
                            <P>(3) If BOEM's emissions inventory is discontinued or delayed for more than 3 consecutive years, then offshore production facilities shall once in every 3 years use the most recent monitoring and calculation methods published by BOEM referenced in 30 CFR 550.302 through 304 to calculate annual emissions for each of the emission source types covered in BOEM's most recently published calculation methods.</P>
                            <P>(4) For the first year of reporting, offshore production facilities must use the most recent monitoring and calculation methods published by BOEM referenced in 30 CFR 550.302 through 304 to calculate and report annual emissions.</P>
                            <P>
                                <E T="03">(t) GHG volumetric emissions using actual conditions.</E>
                                 If equation parameters in § 98.233 are already determined at standard conditions as provided in the introductory text in § 98.233, which results in volumetric emissions at standard conditions, then this paragraph does not apply. Calculate volumetric emissions at standard conditions as specified in paragraph (t)(1) or (2) of this section, with actual pressure and temperature determined by engineering estimates based on best available data unless otherwise specified.
                            </P>
                            <P>
                                (1) Calculate natural gas volumetric emissions at standard conditions using actual natural gas emission temperature and pressure, and equation W-33 to this section for conversions of E
                                <E T="52">a,n</E>
                                 or conversions of FR
                                <E T="52">a</E>
                                 (whether sub-sonic or sonic).
                            </P>
                            <GPH SPAN="3" DEEP="34">
                                <PRTPAGE P="42281"/>
                                <GID>ER14MY24.096</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,n</E>
                                     = Natural gas volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet, except E
                                    <E T="52">s,n</E>
                                     equals FR
                                    <E T="52">s,p</E>
                                     for each well p when calculating either subsonic or sonic flowrates under § 98.233(g).
                                </FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">a,n</E>
                                     = Natural gas volumetric emissions at actual conditions in cubic feet, except E
                                    <E T="52">a,n</E>
                                     equals FR
                                    <E T="52">a,p</E>
                                     for each well p when calculating either subsonic or sonic flowrates under § 98.233(g).
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">s</E>
                                     = Temperature at standard conditions (60 °F).
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">a</E>
                                     = Temperature at actual emission conditions (°F).
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">s</E>
                                     = Absolute pressure at standard conditions (14.7 psia).
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">a</E>
                                     = Absolute pressure at actual conditions (psia).
                                </FP>
                                <FP SOURCE="FP-2">
                                    Z
                                    <E T="52">a</E>
                                     = Compressibility factor at actual conditions for natural gas. You may use either a default compressibility factor of 1, or a site-specific compressibility factor based on actual temperature and pressure conditions.
                                </FP>
                            </EXTRACT>
                            <P>(2) Calculate GHG volumetric emissions at standard conditions using actual GHG emissions temperature and pressure, and equation W-34 to this section.</P>
                            <GPH SPAN="3" DEEP="34">
                                <GID>ER14MY24.097</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i</E>
                                     = GHG i volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">a,i</E>
                                     = GHG i volumetric emissions at actual conditions in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">s</E>
                                     = Temperature at standard conditions (60 °F).
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">a</E>
                                     = Temperature at actual emission conditions (°F).
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">s</E>
                                     = Absolute pressure at standard conditions (14.7 psia).
                                </FP>
                                <FP SOURCE="FP-2">
                                    P
                                    <E T="52">a</E>
                                     = Absolute pressure at actual conditions (psia).
                                </FP>
                                <FP SOURCE="FP-2">
                                    Z
                                    <E T="52">a</E>
                                     = Compressibility factor at actual conditions for GHG
                                    <E T="52">i</E>
                                    . You may use either a default compressibility factor of 1, or a site-specific compressibility factor based on actual temperature and pressure conditions.
                                </FP>
                            </EXTRACT>
                            <P>(3) Reporters using 68 °F for standard temperature may use the ratio 519.67/527.67 to convert volumetric emissions from 68 °F to 60 °F.</P>
                            <P>
                                (u) 
                                <E T="03">GHG volumetric emissions at standard conditions.</E>
                                 Calculate GHG volumetric emissions at standard conditions as specified in paragraphs (u)(1) and (2) of this section.
                            </P>
                            <P>
                                (1) Estimate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions from natural gas emissions using equation W-35 to this section.
                            </P>
                            <GPH SPAN="3" DEEP="15">
                                <GID>ER14MY24.098</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i</E>
                                     = GHG i (either CH
                                    <E T="52">4</E>
                                     or CO
                                    <E T="52">2</E>
                                    ) volumetric emissions at standard conditions in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,n</E>
                                     = Natural gas volumetric emissions at standard conditions in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    M
                                    <E T="52">i</E>
                                     = Mole fraction of GHG i in the natural gas.
                                </FP>
                            </EXTRACT>
                            <P>
                                (2) For equation W-35 to this section, the mole fraction, M
                                <E T="52">i</E>
                                , shall be the annual average mole fraction for each sub-basin category or facility, as specified in paragraphs (u)(2)(i) through (vii) of this section.
                            </P>
                            <P>
                                (i) 
                                <E T="03">GHG mole fraction in produced natural gas for onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities.</E>
                                 If you have a continuous gas composition analyzer for produced natural gas, you must use an annual average of these values for determining the mole fraction. If you do not have a continuous gas composition analyzer, then you must use an annual average gas composition based on your most recent available analysis of the sub-basin category or facility, as applicable to the emission source.
                            </P>
                            <P>
                                (ii) 
                                <E T="03">GHG mole fraction in feed natural gas for all emissions sources upstream of the de-methanizer or dew point control and GHG mole fraction in facility specific residue gas to transmission pipeline systems for all emissions sources downstream of the de-methanizer overhead or dew point control for onshore natural gas processing facilities.</E>
                                 For onshore natural gas processing plants that solely fractionate a liquid stream, use the GHG mole percent in feed natural gas liquid for all streams. If you have a continuous gas composition analyzer on feed natural gas, you must use these values for determining the mole fraction. If you do not have a continuous gas composition analyzer, then annual samples must be taken according to methods set forth in § 98.234(b).
                            </P>
                            <P>
                                (iii) 
                                <E T="03">GHG mole fraction in transmission pipeline natural gas that passes through the facility for the onshore natural gas transmission compression industry segment and the onshore natural gas transmission pipeline industry segment.</E>
                                 You may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data.
                            </P>
                            <P>
                                (iv) 
                                <E T="03">GHG mole fraction in natural gas stored in the underground natural gas storage industry segment.</E>
                                 You may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data.
                            </P>
                            <P>
                                (v) 
                                <E T="03">GHG mole fraction in natural gas stored in the LNG storage industry segment.</E>
                                 You may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data.
                            </P>
                            <P>
                                (vi) 
                                <E T="03">GHG mole fraction in natural gas stored in the LNG import and export industry segment.</E>
                                 For export facilities that receive gas from transmission pipelines, you may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific 
                                <PRTPAGE P="42282"/>
                                engineering estimates based on best available data.
                            </P>
                            <P>
                                (vii) 
                                <E T="03">GHG mole fraction in local distribution pipeline natural gas that passes through the facility for natural gas distribution facilities.</E>
                                 You may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data.
                            </P>
                            <P>
                                (v) 
                                <E T="03">GHG mass emissions.</E>
                                 Calculate GHG mass emissions in metric tons by converting the GHG volumetric emissions at standard conditions into mass emissions using equation W-36 to this section.
                            </P>
                            <GPH SPAN="3" DEEP="16">
                                <GID>ER14MY24.099</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    Mass
                                    <E T="52">i</E>
                                     = GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                    , CO
                                    <E T="52">2</E>
                                    , or N
                                    <E T="52">2</E>
                                    O) mass emissions in metric tons.
                                </FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,i</E>
                                     = GHG
                                    <E T="52">i</E>
                                     (either CH
                                    <E T="52">4</E>
                                    , CO
                                    <E T="52">2</E>
                                    , or N
                                    <E T="52">2</E>
                                    O) volumetric emissions at standard conditions, in cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    ρ
                                    <E T="52">i</E>
                                     = Density of GHG
                                    <E T="52">i</E>
                                    . Use 0.0526 kg/ft
                                    <E T="51">3</E>
                                     for CO
                                    <E T="52">2</E>
                                     and N
                                    <E T="52">2</E>
                                    O, and 0.0192 kg/ft
                                    <E T="51">3</E>
                                     for CH
                                    <E T="52">4</E>
                                     at 60 °F and 14.7 psia.
                                </FP>
                            </EXTRACT>
                            <P>
                                (w) 
                                <E T="03">EOR injection pump blowdown.</E>
                                 Calculate CO
                                <E T="52">2</E>
                                 pump blowdown emissions from each EOR injection pump system as follows:
                            </P>
                            <P>(1) Calculate the total injection pump system volume in cubic feet (including pipelines, manifolds and vessels) between isolation valves.</P>
                            <P>(2) Retain logs of the number of blowdowns per calendar year.</P>
                            <P>
                                (3) Calculate the total annual CO
                                <E T="52">2</E>
                                 emissions from each EOR injection pump system using equation W-37 to this section:
                            </P>
                            <GPH SPAN="3" DEEP="17">
                                <GID>ER14MY24.100</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    Mass
                                    <E T="52">CO</E>
                                    <E T="0362">2</E>
                                     = Annual EOR injection pump system emissions in metric tons from blowdowns.
                                </FP>
                                <FP SOURCE="FP-2">N = Number of blowdowns for the EOR injection pump system in the calendar year.</FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">v</E>
                                     = Total volume in cubic feet of EOR injection pump system chambers (including pipelines, manifolds and vessels) between isolation valves.
                                </FP>
                                <FP SOURCE="FP-2">
                                    R
                                    <E T="52">c</E>
                                     = Density of critical phase EOR injection gas in kg/ft
                                    <E T="51">3</E>
                                    . You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice to determine density of super critical EOR injection gas.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">CO</E>
                                    <E T="0362">2</E>
                                     = Mass fraction of CO
                                    <E T="52">2</E>
                                     in critical phase injection gas.
                                </FP>
                                <FP SOURCE="FP-2">
                                    1 × 10
                                    <E T="51">−3</E>
                                     = Conversion factor from kilograms to metric tons.
                                </FP>
                            </EXTRACT>
                            <P>
                                (x) 
                                <E T="03">EOR hydrocarbon liquids dissolved CO</E>
                                <E T="54">2</E>
                                . Calculate CO
                                <E T="52">2</E>
                                 emissions downstream of the storage tank from dissolved CO
                                <E T="52">2</E>
                                 in hydrocarbon liquids produced through EOR operations as follows:
                            </P>
                            <P>
                                (1) Determine the amount of CO
                                <E T="52">2</E>
                                 retained in hydrocarbon liquids after flashing in tankage at STP conditions. Annual samples of hydrocarbon liquids downstream of the storage tank must be taken according to methods set forth in § 98.234(b) to determine retention of CO
                                <E T="52">2</E>
                                 in hydrocarbon liquids immediately downstream of the storage tank. Use the annual analysis for the calendar year.
                            </P>
                            <P>(2) Estimate emissions using equation W-38 to this section.</P>
                            <GPH SPAN="3" DEEP="15">
                                <GID>ER14MY24.101</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    Mass
                                    <E T="52">CO</E>
                                    <E T="0362">2</E>
                                     = Annual CO
                                    <E T="52">2</E>
                                     emissions from CO
                                    <E T="52">2</E>
                                     retained in hydrocarbon liquids produced through EOR operations beyond tankage, in metric tons.
                                </FP>
                                <FP SOURCE="FP-2">
                                    S
                                    <E T="52">hl</E>
                                     = Amount of CO
                                    <E T="52">2</E>
                                     retained in hydrocarbon liquids downstream of the storage tank, in metric tons per barrel, under standard conditions.
                                </FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">hl</E>
                                     = Total volume of hydrocarbon liquids produced at the EOR operations in barrels in the calendar year.
                                </FP>
                            </EXTRACT>
                            <P>
                                (y) 
                                <E T="03">Other large release events.</E>
                                 Calculate CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 emissions from other large release events as specified in paragraphs (y)(2) through (5) of this section for each release that meets or exceeds the applicable criteria in paragraph (y)(1) of this section. You are not required to measure every release from your facility, but if you have EPA-provided notification(s) under the super emitter program in § 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or if EPA- or facility-funded monitoring or measurement data that demonstrate the release meets or exceeds one of the thresholds or may reasonably be anticipated to meet or exceed (or to have met or exceeded) one of the thresholds in paragraph (y)(1) of this section, then you must calculate the event emissions and, if the thresholds are confirmed to be exceeded, report the emissions as an other large release event. If you receive an EPA-provided notification under the super emitter program in § 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you must comply with the requirements in paragraph (y)(6) of this section.
                            </P>
                            <P>(1) You must report emissions for other large release events that emit GHG at or above any applicable threshold listed in paragraphs (y)(1)(i) or (ii) of this section. You must report the emissions for the entire duration of the event, not just those time periods of the event emissions exceed the thresholds in paragraphs (y)(1)(i) or (ii) of this section.</P>
                            <P>(i) For sources not subject to reporting under paragraphs (a) through (s), (w), (x), (dd), or (ee) of this section (such as but not limited to a fire, explosion, well blowout, or pressure relief), a release that emits methane at any point in time at a rate of 100 kg/hr or greater.</P>
                            <P>
                                (ii) For sources subject to reporting under paragraphs (a) through (h), (j) through (s), (w), (x), (dd), or (ee) of this section, a release that emits methane at any point in time at a rate of 100 kg/hr or greater in excess of the emissions calculated from the source using the applicable methods under paragraphs (a) through (h), (j) through (s), (w), (x), (dd), or (ee) of this section. For a release meeting the criteria in this paragraph (y)(1)(ii), you must report the emissions 
                                <PRTPAGE P="42283"/>
                                as an other large release event and exclude the emissions that would have been calculated for that source during the timespan of the event in the source-specific emissions calculated under paragraphs (a) through (h), (j) through (s), (w), (x), (dd), or (ee) of this section, as applicable.
                            </P>
                            <P>(2) Estimate the total volume of gas released during the event in standard cubic feet and the methane emission rate at any point in time during the event in kilograms per hour using measurement data according to § 98.234(b), if available, or a combination of process knowledge, engineering estimates, and best available data when measurement data are not available according to paragraphs (y)(2)(i) through (v) of this section.</P>
                            <P>
                                (i) The total volume of gas released must be estimated as the product of the measured or estimated average flow or release rate and the estimated event duration. For events for which information is available showing variable or decaying flow rates, you must calculate the maximum natural gas flow or release rate during the event and either determine a representative average release rate across the entire event or determine representative release rates for specific time periods within the event duration. If you elect to determine representative release rates for specific time periods within the event duration, calculate the volume of gas released for each time period within the event duration as the product of the representative release rate and the length of the corresponding time period and sum the volume of gas released across each of the time periods for the full duration of the event. For events that have releases from multiple release points but have a common root cause (
                                <E T="03">e.g.</E>
                                , over-pressuring of a system causes releases from multiple pressure relief devices), you must report the event as a single other large release event considering the cumulative volume of gas released across all release points.
                            </P>
                            <P>(ii) The start time of the event must be determined based on monitored process parameters and sound engineering principles. If monitored process parameters cannot identify the start of the event, the event must be assumed to start on the date of the most recent monitoring or measurement survey that confirms the source was not emitting at or above the rates specified in paragraph (y)(1) of this section or assumed to have started 91 days prior to the date the event was first identified, whichever start date is most recent.</P>
                            <P>(iii) The end time of the event must be the date of the confirmed repair or confirmed cessation of emissions.</P>
                            <P>(iv) For the purposes of paragraph (y)(2)(ii) of this section, “monitoring or measurement survey” includes any monitoring or measurement method in § 98.234(a) through (d) as well as advanced screening methods such as monitoring systems mounted on vehicles, drones, helicopters, airplanes, or satellites capable of identifying emissions at the thresholds specified in paragraph (y)(1) of this section at a 90 percent probability of detection as demonstrated by controlled release tests. Audio, visual, and olfactory inspections are considered monitoring surveys if and only if the event was identified via an audio, visual, and olfactory inspection.</P>
                            <P>(v) For events that span two different reporting years, calculate the portion of the event's volumetric emissions calculated according to paragraph (y)(2)(i) of this section that occurred in each reporting year considering only reporting year 2025 and later reporting years. For events with consistent flow or for which one average emissions rate is used, use the relative duration of the event within each reporting year to apportion the volume of gas released for each reporting year. For variable flow events for which the volume of gas released is estimated for separate time periods, sum the volume of gas released across each of the time periods within a given reporting year separately. If one of the time periods span two different reporting years, calculate the portion of the volumetric emissions calculated for that time period that applies to each reporting year based on the number of hours in that time period within each reporting year.</P>
                            <P>
                                (3) Determine the composition of the gas released to the atmosphere using measurement data, if available, or a combination of process knowledge, engineering estimates, and best available data when measurement data are not available. In the event of an explosion or fire, where a portion of the natural gas may be combusted, estimate the composition of the gas released to the atmosphere considering the fraction of natural gas released directly to the atmosphere and the fraction of natural gas that was combusted by the explosion or fire during the release event. Assume combustion efficiency equals destruction efficiency and assume a maximum combustion efficiency of 92 percent for natural gas that is combusted in an explosion or fire when estimating the CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 composition of the release. You may use different compositions for different periods within the duration if available information suggests composition varied during the release (
                                <E T="03">e.g.</E>
                                , if a portion of the release occurred while fire was present and a portion of the release occurred when no fire was present).
                            </P>
                            <P>(4) Calculate the GHG volumetric emissions using equation W-35 to this section.</P>
                            <P>
                                (5) Calculate both CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.
                            </P>
                            <P>(6) If you receive an EPA-provided notification under the super emitter program in § 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you must include the emissions from that source or event within your subpart W report unless you can provide certification as specified in either paragraph (y)(6)(i) or (ii) of this section, as applicable, or unless the EPA has determined that the notification has a demonstrable error, as specified in paragraph (y)(6)(iii) of this section.</P>
                            <P>(i) If you do not own or operate any petroleum and natural gas system equipment within 50 meters of the location identified in the notification, you may prepare and submit the certification that the facility does not own or operate the equipment at the location identified in the notification.</P>
                            <P>(ii) If you own or operate petroleum and natural gas system equipment within 50 meters of the location identified in the notification, but there are also other petroleum and natural gas system equipment within 50 meters of the location identified in the notification owned and operated by a different facility, you may prepare and submit the certification that the facility does not own or operate the emitting equipment at the location identified in the notification if and only if you comply with all of the following requirements.</P>
                            <P>(A) Within 5 days of receiving the notification, complete an investigation of available data as specified in § 60.5371b(d)(2)(i) through (iv) of this chapter to identify the emissions source related to the event notification.</P>
                            <P>
                                (B) If the data investigation in paragraph (y)(6)(ii)(A) of this section does not identify the emissions source related to the event notification, you must conduct a complete survey of equipment at your facility that is within 50 meters of the location identified in the notification following any one of the methods provided in § 98.234(a)(1) through (3) within 15 days of receiving the notification.
                                <PRTPAGE P="42284"/>
                            </P>
                            <P>(C) The investigations and surveys conducted in paragraphs (y)(6)(ii)(A) and (B) of this section verify that none of the equipment that you own or operate at the location identified in the notification were responsible for the high emissions event.</P>
                            <P>(iii) For consideration of demonstrable error, you must submit a statement of demonstrable error as specified by § 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter. You must report emissions associated with the notification unless the EPA has determined that the notification contained a demonstrable error.</P>
                            <P>
                                (z) 
                                <E T="03">Combustion equipment.</E>
                                 Except as specified in paragraphs (z)(6) and (7) of this section, calculate CO
                                <E T="52">2</E>
                                , CH
                                <E T="52">4</E>
                                , and N
                                <E T="52">2</E>
                                O combustion-related emissions from stationary or portable equipment using the applicable method in paragraphs (z)(1) through (3) of this section according to the fuel combusted as specified in those paragraphs:
                            </P>
                            <P>(1) If a fuel combusted in the stationary or portable equipment meets the specifications of paragraph (z)(1)(i) of this section, then calculate emissions according to paragraph (z)(1)(ii) of this section.</P>
                            <P>(i) The fuel combusted in the stationary or portable equipment is listed in table C-1 to subpart C of this part or is a blend in which all fuels are listed in table C-1. If the fuel is natural gas or the blend contains natural gas, the natural gas must also meet the criteria of paragraphs (z)(1)(i)(A) and (B) of this section.</P>
                            <P>(A) The natural gas must be of pipeline quality specification.</P>
                            <P>(B) The natural gas must have a minimum higher heating value of 950 Btu per standard cubic foot.</P>
                            <P>
                                (ii) For fuels listed in paragraph (z)(1)(i) of this section, calculate CO
                                <E T="52">2</E>
                                , CH
                                <E T="52">4</E>
                                , and N
                                <E T="52">2</E>
                                O emissions for each unit or group of units combusting the same fuel according to any Tier listed in subpart C of this part, except that each natural gas-fired reciprocating internal combustion engine or gas turbine must use one of the methods in paragraph (z)(4) of this section to quantify a CH
                                <E T="52">4</E>
                                 emission factor instead of using the CH
                                <E T="52">4</E>
                                 emission factor in table C-2 to subpart C of this part. You must follow all applicable calculation requirements for that tier listed in § 98.33, any monitoring or QA/QC requirements listed for that tier in § 98.34, any missing data procedures specified in § 98.35, and any recordkeeping requirements specified in § 98.37. You must report emissions according to paragraph (z)(5) of this section.
                            </P>
                            <P>(2) If a fuel combusted in the stationary or portable equipment meets the specifications of paragraph (z)(2)(i) of this section, then calculate emissions according to paragraph (z)(2)(ii) of this section.</P>
                            <P>(i) The fuel combusted in the stationary or portable equipment is natural gas that is not pipeline quality or it is a blend containing natural gas that is not pipeline quality with only fuels that are listed in table C-1. The natural gas must meet the criteria of paragraphs (z)(2)(i)(A) through (C) of this section.</P>
                            <P>(A) The natural gas must have a minimum higher heating value of 950 Btu per standard cubic foot.</P>
                            <P>
                                (B) The natural gas must have a maximum CO
                                <E T="52">2</E>
                                 content of higher heating value of 1,100 Btu per standard cubic foot.
                            </P>
                            <P>
                                (C) The natural gas must have a minimum CH
                                <E T="52">4</E>
                                 content of 70 percent by volume.
                            </P>
                            <P>
                                (ii) For fuels listed in paragraph (z)(2)(i) of this section, calculate CO
                                <E T="52">2</E>
                                , CH
                                <E T="52">4</E>
                                , and N
                                <E T="52">2</E>
                                O emissions for each unit or group of units combusting the same fuel according to Tier 2, Tier 3, or Tier 4 listed in subpart C of this part, except that each natural gas-fired reciprocating engine or gas turbine must use one of the methods in paragraph (z)(4) of this section to quantify a CH
                                <E T="52">4</E>
                                 emission factor instead of using the CH
                                <E T="52">4</E>
                                 emission factor in table C-2 to subpart C of this part. You must follow all applicable calculation requirements for that tier listed in § 98.33, any monitoring or QA/QC requirements listed for that tier in § 98.34, any missing data procedures specified in § 98.35, and any recordkeeping requirements specified in § 98.37. You must report emissions according to paragraph (z)(5) of this section.
                            </P>
                            <P>(3) If a fuel combusted in the stationary or portable equipment meets the specifications of paragraph (z)(3)(i) of this section, then calculate emissions according to paragraph (z)(3)(ii) of this section.</P>
                            <P>(i) The fuel combusted in the stationary or portable equipment does not meet the criteria of either paragraph (z)(1)(i) or (z)(2)(i) of this section. Examples include natural gas that is not of pipeline quality, natural gas that has a higher heating value of less than 950 Btu per standard cubic feet, and natural gas that is not pipeline quality and does not meet the criteria of either paragraph (z)(2)(i)(B) or (C) of this section. Other examples include field gas that does not meet the definition of natural gas in § 98.238 and blends containing field gas that does not meet the definition of natural gas in § 98.238.</P>
                            <P>(ii) For fuels listed in paragraph (z)(3)(i) of this section, calculate combustion emissions for each unit or group of units combusting the same fuel using the applicable steps from paragraphs (z)(3)(ii)(A) through (G) of this section:</P>
                            <P>(A) You may use company records to determine the volume of fuel combusted in the unit or group of units during the reporting year.</P>
                            <P>(B) If you have a continuous gas composition analyzer on fuel to the combustion unit(s), you must use these compositions for determining the concentration of each constituent in the flow of gas to the unit or group of units. If you do not have a continuous gas composition analyzer on gas to the combustion unit(s), you may use engineering estimates based on best available data to determine the concentration of each constituent in the flow of gas to the unit or group of units. Otherwise, you must use the appropriate gas compositions for each stream going to the combustion unit(s) as specified in paragraph (u)(2) of this section.</P>
                            <P>
                                (C) For reciprocating internal combustion engines or gas turbines, you may conduct a performance test following the applicable procedures in § 98.234(i) and calculate CH
                                <E T="52">4</E>
                                 emissions in accordance with paragraph (z)(3)(ii)(G) of this section. Otherwise, you must calculate CH
                                <E T="52">4</E>
                                 emissions in accordance with paragraphs (z)(3)(ii)(D) through (F) of this section.
                            </P>
                            <P>(D) Calculate GHG volumetric emissions at actual conditions using equations W-39A and W-39B to this section:</P>
                            <GPH SPAN="3" DEEP="31">
                                <GID>ER14MY24.102</GID>
                            </GPH>
                            <GPH SPAN="3" DEEP="18">
                                <PRTPAGE P="42285"/>
                                <GID>ER14MY24.103</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">a,CO</E>
                                    <E T="0362">2</E>
                                     = Contribution of annual CO
                                    <E T="52">2</E>
                                     emissions from portable or stationary fuel combustion sources in cubic feet, under actual conditions.
                                </FP>
                                <FP SOURCE="FP-2">
                                    V
                                    <E T="52">a</E>
                                     = Volume of gas sent to the combustion unit or group of units in actual cubic feet, during the year.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Y
                                    <E T="52">CO</E>
                                    <E T="0362">2</E>
                                     = Mole fraction of CO
                                    <E T="52">2</E>
                                     in gas sent to the combustion unit or group of units.
                                </FP>
                                <FP SOURCE="FP-2">η = Fraction of gas combusted for portable and stationary equipment determined using engineering estimation. For internal combustion devices that are not reciprocating internal combustion engines or gas turbines, a default of 0.995 can be used. For two-stroke lean-burn reciprocating internal combustion engines, a default of 0.953 must be used; for four-stroke lean-burn reciprocating internal combustion engines, a default of 0.962 must be used; for four-stroke rich-burn reciprocating internal combustion engines, a default of 0.997 must be used, and for gas turbines, a default of 0.999 must be used.</FP>
                                <FP SOURCE="FP-2">
                                    Y
                                    <E T="52">j</E>
                                     = Mole fraction of hydrocarbon constituent j (such as methane, ethane, propane, butane, and pentanes plus) in gas sent to the combustion unit or group of units.
                                </FP>
                                <FP SOURCE="FP-2">
                                    R
                                    <E T="52">j</E>
                                     = Number of carbon atoms in the hydrocarbon constituent j in gas sent to the combustion unit or group of units; 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes plus.
                                </FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">a,CH</E>
                                    <E T="0362">4</E>
                                     = Contribution of annual CH
                                    <E T="52">4</E>
                                     emissions from portable or stationary fuel combustion sources in cubic feet, under actual conditions.
                                </FP>
                                <FP SOURCE="FP-2">
                                    Y
                                    <E T="52">CH4</E>
                                     = Mole fraction of methane in gas sent to the combustion unit or group of units.
                                </FP>
                            </EXTRACT>
                            <P>(E) Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section.</P>
                            <P>
                                (F) Calculate both combustion-related CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 mass emissions from volumetric CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 emissions using calculation in paragraph (v) of this section.
                            </P>
                            <P>
                                (G) Calculate CH
                                <E T="52">4</E>
                                 and N
                                <E T="52">2</E>
                                O mass emissions, as applicable, using equation W-40 to this section.
                            </P>
                            <GPH SPAN="3" DEEP="16">
                                <GID>ER14MY24.104</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    Mass
                                    <E T="52">i</E>
                                     = Annual N
                                    <E T="52">2</E>
                                    O or CH
                                    <E T="52">4</E>
                                     emissions from the combustion of a particular type of fuel (metric tons).
                                </FP>
                                <FP SOURCE="FP-2">Fuel = Annual mass or volume of the fuel combusted (mass or volume per year, choose appropriately to be consistent with the units of HHV).</FP>
                                <FP SOURCE="FP-2">HHV = Site-specific higher heating value of the fuel, mmBtu/unit of the fuel (in units consistent with the fuel quantity combusted).</FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">i</E>
                                     = For N
                                    <E T="52">2</E>
                                    O, use 1.0 × 10
                                    <E T="51">−4</E>
                                     kg N
                                    <E T="52">2</E>
                                    O/mmBtu; for CH
                                    <E T="52">4</E>
                                    , use the CH
                                    <E T="52">4</E>
                                     EF (kg CH
                                    <E T="52">4</E>
                                    /MMBtu) determined from your performance test according to paragraph (z)(4)(i) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    1 × 10
                                    <E T="51">−3</E>
                                     = Conversion factor from kilograms to metric tons.
                                </FP>
                            </EXTRACT>
                            <P>
                                (4) For each natural gas-fired reciprocating internal combustion engine or gas turbine calculating emissions according to paragraph (z)(1)(ii) or (z)(2)(ii) of this section, you must determine a CH
                                <E T="52">4</E>
                                 emission factor (kg CH
                                <E T="52">4</E>
                                /MMBtu) using one of the methods provided in paragraphs (z)(4)(i) through (iii) of this section. For each reciprocating internal combustion engine or gas turbine calculating CH
                                <E T="52">4</E>
                                 emissions according to paragraph (z)(3)(ii)(G) of this section, you must determine a CH
                                <E T="52">4</E>
                                 emission factor (kg CH
                                <E T="52">4</E>
                                /MMBtu) using the method provided in paragraph (z)(4)(i).
                            </P>
                            <P>
                                (i) Conduct a performance test following the applicable procedures in § 98.234(i). If you are required or elect to conduct a performance test for any reason, you must use that result to determine the CH
                                <E T="52">4</E>
                                 emission factors. If multiple performance tests are conducted in the same reporting year, the arithmetic average of all performance tests completed that year must be used to determine the CH
                                <E T="52">4</E>
                                 emission factor.
                            </P>
                            <P>(ii) Original equipment manufacturer information, which may include manufacturer specification sheets, emissions certification data, or other manufacturer data providing expected emission rates from the reciprocating internal combustion engine or gas turbine.</P>
                            <P>(iii) Applicable equipment type-specific emission factor from table W-7 to this subpart.</P>
                            <P>(5) Emissions from fuel combusted in stationary or portable equipment at onshore petroleum and natural gas production facilities, at onshore petroleum and natural gas gathering and boosting facilities, and at natural gas distribution facilities that are calculated according to the procedures in either paragraph (z)(1)(ii) or (z)(2)(ii) of this section must be reported according to the requirements specified in § 98.236(z) rather than the reporting requirements specified in subpart C of this part.</P>
                            <P>(6) External fuel combustion sources with a rated heat capacity equal to or less than 5 mmBtu/hr do not need to report combustion emissions or include these emissions for threshold determination in § 98.231(a). You must report the type and number of each external fuel combustion unit.</P>
                            <P>(7) Internal fuel combustion sources, not compressor-drivers, with a rated heat capacity equal to or less than 1 mmBtu/hr (or the equivalent of 130 horsepower), do not need to report combustion emissions or include these emissions for threshold determination in § 98.231(a). You must report the type and number of each internal fuel combustion unit.</P>
                            <P>(aa) through (cc) [Reserved]</P>
                            <P>
                                (dd) 
                                <E T="03">Drilling mud degassing.</E>
                                 Calculate annual volumetric CH
                                <E T="52">4</E>
                                 emissions from the degassing of drilling mud using one of the calculation methods described in paragraphs (dd)(1), (2), or (3) of this section. If you have taken mudlogging measurements from the penetration of the first hydrocarbon bearing zone until drilling mud ceases to be circulated in the wellbore, including mud pumping rate and gas trap-derived gas concentration that is reported in parts per million (ppm) or is reported in units from which ppm can be derived, you must use Calculation Method 1 as described in paragraph (dd)(1) of this section. If you have not taken mudlogging measurements, you must use Calculation Method 2 as described in paragraph (dd)(2) of this section. If you have taken mudlogging measurements for some, but not all, of the time the well bore has penetrated the first hydrocarbon bearing zone until drilling mud ceases to be circulated in the wellbore including mud pumping rate and gas trap-derived gas concentration that is reported in parts per million (ppm) or is reported in units from which ppm can be derived, you must use Calculation Method 3 as described in paragraph (dd)(3) of this section.
                            </P>
                            <P>
                                (1) 
                                <E T="03">Calculation Method 1.</E>
                                 For each well in the sub-basin in which drilling mud was used during well drilling, you must calculate CH
                                <E T="52">4</E>
                                 emissions from drilling mud degassing by applying an emissions rate derived from a representative well in the same sub-
                                <PRTPAGE P="42286"/>
                                basin and within the equivalent stratigraphic interval. You must follow the procedures specified in paragraph (dd)(1)(i) of this section to calculate CH
                                <E T="52">4</E>
                                 emissions for the representative well and follow the procedures in paragraphs (dd)(1)(ii) through (iv) of this section to calculate CH
                                <E T="52">4</E>
                                 emissions for every well drilled in the sub-basin and within the equivalent stratigraphic interval.
                            </P>
                            <P>
                                (i) Calculate CH
                                <E T="52">4</E>
                                 emissions from mud degassing for one representative well in each sub-basin and within the equivalent stratigraphic interval. For the representative well, you must use mudlogging measurements, including gas trap derived gas concentration and mud pumping rate, taken during the reporting year. In the first year of reporting, you may use measurements from the prior reporting year if measurements from the current reporting year are not available. Use equation W-41 to this section to calculate natural gas emissions from mud degassing at the representative well. You must identify and calculate CH
                                <E T="52">4</E>
                                 emissions for a representative well for the sub-basin and within the equivalent stratigraphic interval every 2 calendar years or on a more frequent basis. If a representative well is not available in the same sub-basin and within the equivalent stratigraphic interval, you may choose a well within the facility that is drilled into the same formation and within the equivalent stratigraphic interval.
                            </P>
                            <GPH SPAN="3" DEEP="25">
                                <GID>ER14MY24.105</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,CH4,r</E>
                                     = Annual total volumetric CH
                                    <E T="52">4</E>
                                     emissions from mud degassing for the representative well, r, in standard cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    MR
                                    <E T="52">r</E>
                                     = Average mud rate for the representative well, r, in gallons per minute.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">r</E>
                                     = Total time that drilling mud is circulated in the representative well, r, in minutes beginning with initial penetration of the first hydrocarbon-bearing zone until drilling mud ceases to be circulated in the wellbore.
                                </FP>
                                <FP SOURCE="FP-2">
                                    X
                                    <E T="52">n</E>
                                     = Average concentration of natural gas in the drilling mud as measured by the gas trap, in parts per million.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">CH4</E>
                                     = Measured mole fraction of CH
                                    <E T="52">4</E>
                                     in natural gas entrained in the drilling mud.
                                </FP>
                                <FP SOURCE="FP-2">0.1337 = Conversion from gallons to standard cubic feet.</FP>
                            </EXTRACT>
                            <P>
                                (ii) Calculate the emissions rate of CH
                                <E T="52">4</E>
                                 in standard cubic feet per minute from the representative well using equation W-42 to this section.
                            </P>
                            <GPH SPAN="3" DEEP="28">
                                <GID>ER14MY24.106</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    ER
                                    <E T="52">s,CH4,r</E>
                                     = Volumetric CH
                                    <E T="52">4</E>
                                     emission rate from mud degassing for the representative well, r, in standard cubic feet per minute.
                                </FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,CH4,r</E>
                                     = Annual total volumetric CH
                                    <E T="52">4</E>
                                     emissions from mud degassing for the representative well, r, in standard cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">r</E>
                                     = Total time that drilling mud is circulated in the representative well, r, in minutes beginning with initial penetration of the first hydrocarbon-bearing zone until drilling mud ceases to be circulated in the wellbore.
                                </FP>
                            </EXTRACT>
                            <P>(iii) Use equation W-43 to this section to calculate emissions for any wells drilled in the same sub-basin and within the equivalent stratigraphic interval in the reporting year.</P>
                            <GPH SPAN="3" DEEP="16">
                                <GID>ER14MY24.107</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">s,CH4,p</E>
                                     = Annual total CH
                                    <E T="52">4</E>
                                     emissions from mud degassing for the well, p, in standard cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    ER
                                    <E T="52">s,CH4,r</E>
                                     = Volumetric CH
                                    <E T="52">4</E>
                                     emission rate from mud degassing for the representative well, r, in standard cubic feet per minute.
                                </FP>
                                <FP SOURCE="FP-2">
                                    T
                                    <E T="52">p</E>
                                     = Total time that drilling mud is circulated in the well, p, during the reporting year, in minutes beginning with initial penetration of the first hydrocarbon-bearing zone until drilling mud ceases to be circulated in the wellbore.
                                </FP>
                            </EXTRACT>
                            <P>
                                (iv) Calculate CH
                                <E T="52">4</E>
                                 mass emissions using calculations in paragraph (v) of this section.
                            </P>
                            <P>
                                (2) 
                                <E T="03">Calculation Method 2.</E>
                                 If you did not take mudlogging measurements, calculate emissions from mud degassing for each well using equation W-44 to this section:
                            </P>
                            <GPH SPAN="3" DEEP="21">
                                <GID>ER14MY24.108</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    Mass
                                    <E T="52">CH4,p</E>
                                     = Annual total CH
                                    <E T="52">4</E>
                                     emissions for the well, p, in metric tons.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF
                                    <E T="52">CH4</E>
                                     = Emission factor in metric tons CH
                                    <E T="52">4</E>
                                     per drilling day. Use 0.2605 for water-based drilling muds, 0.0586 for oil-based drilling muds, and 0.0586 for synthetic drilling muds.
                                </FP>
                                <FP SOURCE="FP-2">
                                    DD
                                    <E T="52">p</E>
                                     = Total number of drilling days for the well, p, when drilling mud is circulated in the wellbore. The first drilling day is the day that the borehole penetrated the first hydrocarbon-bearing zone and the last drilling day is the day drilling mud ceases to be circulated in the wellbore.
                                </FP>
                                <FP SOURCE="FP-2">
                                    X
                                    <E T="52">CH4</E>
                                     = The mole percent of methane in gas vented during mud degassing in the sub-basin in which the well is located and derived from the average mole fraction of CH
                                    <E T="52">4</E>
                                     in produced gas for the sub-basin as reported in § 98.236(aa)(1)(ii)(I).
                                </FP>
                                <FP SOURCE="FP-2">83.85 = The mole percent of methane from the vented gas used to derive the emission factor (EF).</FP>
                            </EXTRACT>
                            <P>
                                (3) 
                                <E T="03">Calculation Method 3</E>
                                . If you have taken mudlogging measurements at 
                                <PRTPAGE P="42287"/>
                                intermittent time intervals for some, but not all, of the time the well bore has penetrated the first hydrocarbon bearing zone until drilling mud ceases to be circulated in the wellbore, you must use Calculation Method 1 to calculate emissions for the cumulative amount of time mudlogging measurements were taken and Calculation Method 2 for the cumulative amount of time mudlogging measurements were not taken. To determine total annual CH
                                <E T="52">4</E>
                                 emissions for the well, add Mass
                                <E T="52">CH4,p</E>
                                 calculated using Calculation Method 2 to E
                                <E T="52">s,CH4,p</E>
                                , if the well is a representative well, or E
                                <E T="52">s,CH4,p</E>
                                , if the well is not a representative well, calculated using Calculation Method 1.
                            </P>
                            <P>
                                (ee) 
                                <E T="03">Crankcase venting.</E>
                                 For each reciprocating internal combustion engine with a rated heat capacity greater than 1 mmBtu/hr (or the equivalent of 130 horsepower), calculate annual CH
                                <E T="52">4</E>
                                 mass emissions from crankcase venting using one of the methods provided in paragraphs (ee)(1) and (2) of this section. If you elect to use the method in paragraph (ee)(1) of this section, you must use the results of the direct measurement to determine the CH
                                <E T="52">4</E>
                                 emissions. If any crankcase vents are routed to a flare, you must calculate CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O emissions for the flare stack as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n). Notwithstanding the calculation and emissions reporting requirements as specified in this paragraph (ee) of this section, the number of reciprocating internal combustion engines with crankcase vents routed to flares must be reported as specified in § 98.236(ee)(1).
                            </P>
                            <P>
                                (1) 
                                <E T="03">Calculation Method 1.</E>
                                 Determine the CH
                                <E T="52">4</E>
                                 mass emissions from reciprocating internal combustion engines annually using the method provided in paragraphs (ee)(1)(i) through (iv) of this section. If you choose to use this method you must use it for all reciprocating internal combustion engines at the facility, well-pad site, or gathering and boosting site, except that if you choose to perform the screening specified in paragraph (ee)(1)(ii) of this section, you must use the method in paragraph (ee)(2) of this section to determine emissions from each reciprocating internal combustion engine that is not operating at the facility, well-pad site, or gathering and boosting site at the time of the screening.
                            </P>
                            <P>(i) Determine the volumetric flow from the crankcase vent at standard conditions using an appropriate meter, calibrated bag, or high volume sampler according to methods set forth in § 98.234(b), (c), and (d), respectively. Each measurement must be conducted within 10 percent of 100 percent peak load. You may not measure during period of startup, shutdown, or malfunction.</P>
                            <P>(ii) You may choose to use any of the methods set forth in § 98.234(a)(1) through (3) to screen for emissions. If emissions are detected using the methods set forth in § 98.234(a)(1) through (3), then you must use one of the methods specified in paragraphs (ee)(1)(i) of this section to determine the volumetric flow from the crank case vent at standard conditions. If emissions are not detected using the methods in § 98.234(a)(1) through (3), then you may assume that the emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a)(1) through (3), emissions are detected whenever a leak is detected according to the method.</P>
                            <P>(iii) If conducting measurements for a manifolded group of crankcase vent sources, you must measure at a single point in the manifold downstream of all crankcase vent inputs and, if practical, prior to comingling with other non-compressor emission sources. Determine the volumetric flow at standard conditions from the common stack using one of the methods specified in paragraph (ee)(1)(i) of this section. If the manifolded group contains only crankcase vent sources, divide the measured volumetric flow equally between all operating reciprocating internal combustion engines. If the manifolded group contains crankcase vent sources and compressor vent sources, follow the methods for manifolded sources provided in paragraphs (o) or (p) of this section, as applicable, and report emissions from the crankcase vent as specified in § 98.236(o) or (p), as applicable.</P>
                            <P>
                                (iv) Using equation W-45 to this section, calculate the annual volumetric CH
                                <E T="52">4</E>
                                 emissions for each reciprocating internal combustion engine that was measured during the reporting year.
                            </P>
                            <GPH SPAN="3" DEEP="15">
                                <GID>ER14MY24.109</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">CH4</E>
                                     = Annual total volumetric emissions of CH
                                    <E T="52">4</E>
                                     from crankcase venting on the reciprocating internal combustion engine, in standard cubic feet.
                                </FP>
                                <FP SOURCE="FP-2">
                                    MT
                                    <E T="52">s,CCV</E>
                                     = Volumetric gas emissions for measured crankcase vent, in standard cubic feet per hour, measured according to paragraph (ee)(1)(i) of this section.
                                </FP>
                                <FP SOURCE="FP-2">
                                    GHG
                                    <E T="52">CH4</E>
                                     = Concentration of CH
                                    <E T="52">4</E>
                                     in the gas stream entering reciprocating internal combustion engine. If the concentration of CH
                                    <E T="52">4</E>
                                     is unknown, use the concentration of CH
                                    <E T="52">4</E>
                                     in the gas stream either using engineering estimates based on best available data or as defined in paragraph (u)(2) of this section.
                                </FP>
                                <FP SOURCE="FP-2">T = Total operating hours per year for the reciprocating internal combustion engine.</FP>
                            </EXTRACT>
                            <P>
                                (v) You must calculate CH
                                <E T="52">4</E>
                                 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.
                            </P>
                            <P>
                                (2) Calculation Method 2. Calculate annual CH
                                <E T="52">4</E>
                                 mass emissions from crankcase venting for each reciprocating internal combustion engine using equation W-46 to this section:
                            </P>
                            <GPH SPAN="3" DEEP="15">
                                <GID>ER14MY24.110</GID>
                            </GPH>
                            <EXTRACT>
                                <FP SOURCE="FP-2">Where:</FP>
                                <FP SOURCE="FP-2">
                                    E
                                    <E T="52">CH4</E>
                                     = Annual total mass emissions of CH
                                    <E T="52">4</E>
                                     from crankcase venting on the reciprocating internal combustion engine, in metric tons.
                                </FP>
                                <FP SOURCE="FP-2">
                                    EF = Emission factor for crankcase venting on the reciprocating internal combustion engine, in kilograms CH
                                    <E T="52">4</E>
                                     per hour per reciprocating internal combustion engine. Use 0.083 kilograms CH
                                    <E T="52">4</E>
                                     per hour per reciprocating internal combustion engine for sources in the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments. Use 0.11 kilograms CH
                                    <E T="52">4</E>
                                     per hour per reciprocating internal combustion engine for sources in all other applicable industry segments.
                                </FP>
                                <FP SOURCE="FP-2">0.001 = Conversion from kilograms to metric tons.</FP>
                                <FP SOURCE="FP-2">T = Total operating hours per year for the reciprocating internal combustion engine.</FP>
                            </EXTRACT>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <PRTPAGE P="42288"/>
                        <AMDPAR>14. Amend § 98.234 by:</AMDPAR>
                        <AMDPAR>a. Revising the introductory text, paragraphs (a)(1) through (3), and (a)(5);</AMDPAR>
                        <AMDPAR>b. Removing paragraphs (a)(6) and (7);</AMDPAR>
                        <AMDPAR>c. Revising paragraph (d)(3);</AMDPAR>
                        <AMDPAR>d. Adding paragraph (d)(5);</AMDPAR>
                        <AMDPAR>e. Removing the text “equation W-41” and “(Eq. W-41)” in paragraph (e) and adding in its place the text “equation W-47” and “(Eq. W-47)”, respectively;</AMDPAR>
                        <AMDPAR>f. Removing and reserving paragraphs (f) and (g); and</AMDPAR>
                        <AMDPAR>g. Adding paragraph (i).</AMDPAR>
                        <P>The revisions and additions read as follows:</P>
                        <SECTION>
                            <SECTNO>§ 98.234</SECTNO>
                            <SUBJECT>Monitoring and QA/QC requirements.</SUBJECT>
                            <P>The GHG emissions data for petroleum and natural gas emissions sources must be quality assured as applicable as specified in this section. Offshore petroleum and natural gas production facilities shall adhere to the monitoring and QA/QC requirements as set forth in 30 CFR part 550.</P>
                            <P>(a) You must use any of the applicable methods described in paragraphs (a)(1) through (5) of this section to conduct leak detection(s) or screening survey(s) as specified in § 98.233(k), (o), (p), and (ee) that occur during a calendar year. You must use any of the methods described in paragraphs (a)(1) through (5) of this section to conduct leak detection(s) of equipment leaks from components as specified in § 98.233(q)(1)(i) or (ii) or (q)(1)(v)(A) that occur during a calendar year. You must use one of the methods described in paragraph (a)(1)(ii) or (iii) or (a)(2)(ii) of this section, as applicable, to conduct leak detection(s) of equipment leaks from components as specified in § 98.233(q)(1)(iii) or (q)(1)(v)(B). If electing to comply with § 98.233(q) as specified in § 98.233(q)(1)(iv), you must use any of the methods described in paragraphs (a)(1) through (5) of this section to conduct leak detection(s) of equipment leaks from component types as specified in § 98.233(q)(1)(iv) that occur during a calendar year. Difficult-to-monitor emissions sources are not exempt from this subpart. If the primary leak detection method employed cannot be used to monitor difficult-to-monitor components without elevating the monitoring personnel more than 2 meters above a support surface, you must use alternative leak detection devices as described in paragraph (a)(1) or (3) of this section to monitor difficult-to-monitor equipment leaks or vented emissions at least once per calendar year.</P>
                            <P>
                                (1) 
                                <E T="03">Optical gas imaging instrument.</E>
                                 Use an optical gas imaging instrument for equipment leak detection as specified in either paragraph (a)(1)(i), (ii), or (iii) of this section. You may use any of the methods as specified in paragraphs (a)(1)(i) through (iii) of this section unless you are required to use a specific method in § 98.233(q)(1).
                            </P>
                            <P>
                                (i) 
                                <E T="03">Optical gas imaging instrument as specified in § 60.18 of this chapter.</E>
                                 Use an optical gas imaging instrument for equipment leak detection in accordance with 40 CFR part 60, subpart A, § 60.18 of the 
                                <E T="03">Alternative work practice for monitoring equipment leaks</E>
                                , § 60.18(i)(1)(i); § 60.18(i)(2)(i) except that the minimum monitoring frequency shall be annual using the detection sensitivity level of 60 grams per hour as stated in 40 CFR part 60, subpart A, Table 1: 
                                <E T="03">Detection Sensitivity Levels;</E>
                                 § 60.18(i)(2)(ii) and (iii) except the gas chosen shall be methane, and § 60.18(i)(2)(iv) and (v); § 60.18(i)(3); § 60.18(i)(4)(i) and (v); including the requirements for daily instrument checks and distances, and excluding requirements for video records. Any emissions detected by the optical gas imaging instrument from an applicable component is a leak. In addition, you must operate the optical gas imaging instrument to image the source types required by this subpart in accordance with the instrument manufacturer's operating parameters.
                            </P>
                            <P>
                                (ii) 
                                <E T="03">Optical gas imaging instrument as specified in § 60.5397a of this chapter.</E>
                                 Use an optical gas imaging instrument for equipment leak detection in accordance with § 60.5397a (c)(3) and (7), and (e) of this chapter and paragraphs (a)(1)(ii)(A) through (C) of this section.
                            </P>
                            <P>(A) For the purposes of this subpart, any visible emissions observed by the optical gas imaging instrument from a component required or elected to be monitored as specified in § 98.233(q)(1) is a leak.</P>
                            <P>(B) For the purposes of this subpart, the term “fugitive emissions component” in § 60.5397a of this chapter means “component.”</P>
                            <P>(C) For the purpose of complying with § 98.233(q)(1)(iv), the phrase “the collection of fugitive emissions components at well sites and compressor stations” in § 60.5397a of this chapter means “the collection of components for which you elect to comply with § 98.233(q)(1)(iv).”</P>
                            <P>
                                (iii) 
                                <E T="03">Optical gas imaging instrument as specified in appendix K to part 60 of this chapter</E>
                                . Use an optical gas imaging instrument for equipment leak detection in accordance with appendix K to part 60, 
                                <E T="03">Determination of Volatile Organic Compound and Greenhouse Gas Leaks Using Optical Gas Imaging.</E>
                                 Any emissions detected by the optical gas imaging instrument from an applicable component is a leak.
                            </P>
                            <P>
                                (2) 
                                <E T="03">Method 21.</E>
                                 Use the equipment leak detection methods in Method 21 in appendix A-7 to part 60 of this chapter as specified in paragraph (a)(2)(i) or (ii) of this section. You may use either of the methods as specified in paragraphs (a)(2)(i) and (ii) of this section unless you are required to use a specific method in § 98.233(q)(1). You must survey all applicable source types at the facility needed to conduct a complete equipment leak survey as defined in § 98.233(q)(1). For the purposes of this subpart, the term “fugitive emissions component” in § 60.5397a of this chapter and § 60.5397b of this chapter means “component.”
                            </P>
                            <P>
                                (i) 
                                <E T="03">Method 21 with a leak definition of 10,000 ppm.</E>
                                 Use the equipment leak detection methods in Method 21 in appendix A-7 to part 60 of this chapter using methane as the reference compound. If an instrument reading of 10,000 ppm or greater is measured for any applicable component, a leak is detected.
                            </P>
                            <P>
                                (ii) 
                                <E T="03">Method 21 with a leak definition of 500 ppm.</E>
                                 Use the equipment leak detection methods in Method 21 in appendix A-7 to part 60 of this chapter using methane as the reference compound. If an instrument reading of 500 ppm or greater is measured for any applicable component, a leak is detected.
                            </P>
                            <P>
                                (3) 
                                <E T="03">Infrared laser beam illuminated instrument.</E>
                                 Use an infrared laser beam illuminated instrument for equipment leak detection. Any emissions detected by the infrared laser beam illuminated instrument is a leak. In addition, you must operate the infrared laser beam illuminated instrument to detect the source types required by this subpart in accordance with the instrument manufacturer's operating parameters.
                            </P>
                            <STARS/>
                            <P>
                                (5) 
                                <E T="03">Acoustic leak detection device.</E>
                                 Use the acoustic leak detection device to detect through-valve leakage. When using the acoustic leak detection device to quantify the through-valve leakage, you must use the instrument manufacturer's calculation methods to quantify the through-valve leak. When using the acoustic leak detection device, if a leak of 3.1 scf per hour or greater is calculated, a leak is detected. In addition, you must operate the acoustic leak detection device to monitor the source valves required by this subpart in accordance with the instrument manufacturer's operating parameters. Acoustic stethoscope type devices designed to detect through valve leakage when put in contact with the valve body 
                                <PRTPAGE P="42289"/>
                                and that provide an audible leak signal but do not calculate a leak rate can be used to identify through-valve leakage. For these acoustic stethoscope type devices, a leak is detected if an audible leak signal is observed or registered by the device. If the acoustic stethoscope type device is used as a screening to a measurement method and a leak is detected, the leak must be measured using any one of the methods specified in paragraphs (b) through (d) of this section.
                            </P>
                            <STARS/>
                            <P>(d) * * *</P>
                            <P>
                                (3) For high volume samplers that output methane mass emissions, you must use the calculations in § 98.233(u) and (v) in reverse to determine the natural gas volumetric emissions at standard conditions. For high volume samplers that output methane volumetric flow in actual conditions, divide the volumetric methane flow rate by the mole fraction of methane in the natural gas according to the provisions in § 98.233(u) and estimate natural gas volumetric emissions at standard conditions using calculations in § 98.233(t). Estimate CH
                                <E T="52">4</E>
                                 and CO
                                <E T="52">2</E>
                                 volumetric and mass emissions from volumetric natural gas emissions using the calculations in § 98.233(u) and (v).
                            </P>
                            <STARS/>
                            <P>
                                (5) If the measured methane flow exceeds the manufacturer's reported quantitation limit or if the measured natural gas flow determined as specified in paragraph (d)(3) of this section exceeds 70 percent of the manufacturer's reported maximum sampling flow rate, then the flow exceeds the capacity of the instrument and you must either use a temporary or permanent flow meter according to paragraph (b) of this section or use calibrated bags according to paragraph (c) of this section to determine the leak or flow rate. If you elect to use OGI to demonstrate that 100 percent of the flow is captured by the high volume sampler throughout the measurement period, then the measured flow rate above the 70 percent maximum sampling rate provision can be used. However, if any emissions are observed via OGI escaping capture of the high volume sampler during a measurement period, then that measurement is considered invalid (
                                <E T="03">i.e.,</E>
                                 considered to be exceeding the quantitation capacity of the device) even if the measured flow rate is less than 70 percent of the sampling rate and you must either use a temporary or permanent flow meter according to paragraph (b) of this section or use calibrated bags according to paragraph (c) of this section to determine the leak or flow rate.
                            </P>
                            <STARS/>
                            <P>(e) Peng Robinson Equation of State means the equation of state defined by equation W-47 to this section:</P>
                            <GPH SPAN="3" DEEP="30">
                                <GID>ER14MY24.111</GID>
                            </GPH>
                            <P>(i) You must use any of the applicable methods described in paragraphs (i)(1) through (4) of this section to conduct a performance test to determine the concentration of CH4 in the exhaust gas. This concentration must be used to develop a CH4 emission factor (kg/MMBtu) for estimating combustion slip from reciprocating internal combustion engines or gas turbines as specified in § 98.233(z)(4). You may not conduct performance tests during period of startup, shutdown or malfunction. You must conduct three separate test runs for each performance test. Each test run must be conducted within 10 percent of 100 percent peak (or the highest achievable) load and last at least 1 hour.</P>
                            <P>(1) EPA Method 18 in appendix A-6 to part 60 of this chapter.</P>
                            <P>(2) EPA Method 320 in appendix A to part 63 of this chapter.</P>
                            <P>(3) ASTM D6348-12 (Reapproved 2020) (incorporated by reference, see § 98.7).</P>
                            <P>(4) EPA Method 25A in appendix A-7 to part 60 of this chapter, with the use of nonmethane cutter as described in § 1065.265 of this chapter.</P>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>15. Amend § 98.235 by revising paragraph (f) to read as follows:</AMDPAR>
                        <SECTION>
                            <SECTNO>§ 98.235</SECTNO>
                            <SUBJECT>Procedures for estimating missing data.</SUBJECT>
                            <STARS/>
                            <P>(f) For the first 6 months of required data collection, facilities that are currently subject to this subpart W and that start up new emission sources or acquire new sources from another facility that were not previously subject to this subpart W may use best engineering estimates for any data related to those newly operating or newly acquired sources that cannot reasonably be measured or obtained according to the requirements of this subpart.</P>
                            <STARS/>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>16. Effective July 15, 2024, amend § 98.236 by:</AMDPAR>
                        <AMDPAR>a. Revising paragraphs (b), (c), and (d)(2)(iii) introductory text;</AMDPAR>
                        <AMDPAR>b. Adding paragraph (d)(2)(iii)(M);</AMDPAR>
                        <AMDPAR>c. Revising paragraphs (e) introductory text, (e)(1) introductory text, (e)(2) introductory text, (e)(2)(i), and (g)(5) introductory text;</AMDPAR>
                        <AMDPAR>d. Adding paragraph (g)(5)(iv);</AMDPAR>
                        <AMDPAR>e. Revising paragraph (g)(6) introductory text;</AMDPAR>
                        <AMDPAR>f. Redesignating paragraph (g)(6)(iii) as (g)(6)(iv);</AMDPAR>
                        <AMDPAR>g. Adding new paragraph (g)(6)(iii);</AMDPAR>
                        <AMDPAR>h. Revising paragraphs (j)(2)(i)(A) and (m)(4) through (6);</AMDPAR>
                        <AMDPAR>i. Redesignating paragraphs (m)(7)(ii) and (iii) as (m)(7)(iii) and (iv), respectively;</AMDPAR>
                        <AMDPAR>j. Adding new paragraph (m)(7)(ii);</AMDPAR>
                        <AMDPAR>k. Revising paragraphs (o) introductory text, (p) introductory text, and (q)(1) introductory text;</AMDPAR>
                        <AMDPAR>l. Adding paragraph (q)(1)(vi); and</AMDPAR>
                        <AMDPAR>m. Revising paragraph (q)(2).</AMDPAR>
                        <P>The revisions and additions read as follows:</P>
                        <SECTION>
                            <SECTNO>§ 98.236</SECTNO>
                            <SUBJECT>Data reporting requirements.</SUBJECT>
                            <STARS/>
                            <P>(b) Natural gas pneumatic devices. You must indicate whether the facility contains the following types of equipment: Continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, and intermittent bleed natural gas pneumatic devices. If the facility contains any continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, or intermittent bleed natural gas pneumatic devices, then you must report the information specified in paragraphs (b)(1) through (b)(6) of this section, as applicable.</P>
                            <P>(1) [Reserved]</P>
                            <P>(2) The number of natural gas pneumatic devices as specified in paragraphs (b)(2)(i) through (viii) of this section, as applicable.</P>
                            <P>(i) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed), determined according to § 98.233(a)(5) through (7).</P>
                            <P>
                                (ii) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented 
                                <PRTPAGE P="42290"/>
                                directly to the atmosphere, determined according to § 98.233(a)(5) through (7).
                            </P>
                            <P>(iii) [Reserved]</P>
                            <P>(iv) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere for which emissions were calculated using Calculation Method 1 according to § 98.233(a)(1).</P>
                            <P>(v) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere for which emissions were calculated using Calculation Method 2 according to § 98.233(a)(2).</P>
                            <P>(vi) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere for which emissions were calculated using Calculation Method 3 according to § 98.233(a)(3).</P>
                            <P>(vii) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) for which emissions were calculated using Calculation Method 4 according to § 98.233(a)(4).</P>
                            <P>(viii) If the reported values in paragraphs (b)(2)(i) through (vii) of this section are estimated values determined according to § 98.233(a)(6), then you must report the information specified in paragraphs (b)(2)(viii)(A) through (C) of this section.</P>
                            <P>(A) The number of natural gas pneumatic devices of each type reported in paragraphs (b)(2)(i) through (vii) of this section that are counted.</P>
                            <P>(B) The number of natural gas pneumatic devices of each type reported in paragraph (b)(2)(i) through (vii) of this section that are estimated (not counted).</P>
                            <P>(C) Whether the calendar year is the first calendar year of reporting or the second calendar year of reporting.</P>
                            <P>(3) For natural gas pneumatic devices vented directly to the atmosphere for which emissions were calculated using Calculation Method 1 according to § 98.233(a)(1), report the information in paragraphs (b)(3)(i) through (vi) of this section for each measurement location.</P>
                            <P>(i) Unique measurement location identification number.</P>
                            <P>(ii) Type of flow monitor (volumetric flow monitor; mass flow monitor).</P>
                            <P>(iii) Number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) downstream of the flow monitor.</P>
                            <P>(iv) An indication of whether a natural gas driven pneumatic pump is also downstream of the flow monitor.</P>
                            <P>
                                (v) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for the natural gas pneumatic devices calculated according to § 98.233(a)(1) for the measurement location.
                            </P>
                            <P>
                                (vi) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for the natural gas pneumatic devices calculated according to § 98.233(a)(1) for the measurement location.
                            </P>
                            <P>(4) For natural gas pneumatic devices vented directly to the atmosphere for which emissions were calculated using Calculation Method 2 according to § 98.233(a)(2), report the information in paragraphs (b)(4)(i) or (ii) of this section, as applicable.</P>
                            <P>(i) For onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities:</P>
                            <P>(A) Indicate the primary measurement method used (temporary flow meter, calibrated bagging, or high volume sampler).</P>
                            <P>
                                (B) The average number of hours each type of the natural gas pneumatic device (continuous low bleed, continuous high bleed, and intermittent bleed) was in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) in the calendar year.
                            </P>
                            <P>
                                (C) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , cumulative by type of natural gas pneumatic device for which emissions were directly measured and calculated as specified in § 98.233(a)(2)(iii) through (viii).
                            </P>
                            <P>
                                (D) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , cumulative by type of natural gas pneumatic device for which emissions were directly measured and calculated as specified in § 98.233(a)(2)(iii) through (viii).
                            </P>
                            <P>(ii) For onshore natural gas processing facilities, onshore natural gas transmission compression facilities, underground natural gas storage facilities, and natural gas distribution facilities:</P>
                            <P>(A) The number of years used in the current measurement cycle.</P>
                            <P>(B) Indicate the primary measurement method used (temporary flow meter, calibrated bagging, or high volume sampler) to measure the emissions from natural gas pneumatic devices at this facility.</P>
                            <P>(C) Indicate whether the emissions from any natural gas pneumatic devices at this facility were calculated using equation W-1B to § 98.233.</P>
                            <P>(D) If the emissions from any natural gas pneumatic devices at this facility were calculated using equation W-1B to § 98.233, report the following information for each type of natural gas pneumatic device (continuous low bleed, continuous high bleed, and intermittent bleed).</P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) The value of the emission factor for the reporting year as calculated using equation W-1A to § 98.233 (in scf/hour/device).
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) The total number of natural gas pneumatic devices measured across all years upon which the emission factor is based (
                                <E T="03">i.e.,</E>
                                 the cumulative value of “Σ
                                <E T="54">n</E>
                                <E T="52">y=1</E>
                                  
                                <E T="03">Count</E>
                                <E T="54">t,y</E>
                                ” in equation W-1A to § 98.233).
                            </P>
                            <P>
                                (
                                <E T="03">3</E>
                                ) Total number of natural gas pneumatic devices that vent directly to the atmosphere and that were not directly measured according to the requirements in § 98.233(a)(1) or (a)(2)(iii) (“Count
                                <E T="52">t</E>
                                ” in equation W-1B to § 98.233).
                            </P>
                            <P>
                                (
                                <E T="03">4</E>
                                ) The average estimated number of hours in the operating year the natural gas pneumatic devices were in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) (“T
                                <E T="52">t</E>
                                ” in equation W-1B to § 98.233).
                            </P>
                            <P>
                                (E) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , cumulative by type of natural gas pneumatic device for which emissions were directly measured and calculated as specified in § 98.233(a)(2)(iii) through (viii).
                            </P>
                            <P>
                                (F) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , cumulative by type of natural gas pneumatic device for which emissions were directly measured and calculated as specified in § 98.233(a)(2)(iii) through (viii).
                            </P>
                            <P>
                                (G) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , cumulative by type of natural gas pneumatic device for which emissions were calculated according to § 98.233(a)(2)(ix). Enter 0 if all devices at this facility were monitored during the reporting year.
                            </P>
                            <P>
                                (H) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , cumulative by type of natural gas pneumatic device for which emissions were calculated according to § 98.233(a)(2)(ix). Enter 0 if all devices at this facility were monitored during the reporting year.
                            </P>
                            <P>(5) For natural gas pneumatic devices vented directly to the atmosphere for which emissions were calculated using Calculation Method 3 according to § 98.233(a)(3), report the information in paragraphs (b)(5)(i) through (iv) of this section.</P>
                            <P>(i) For continuous high bleed and continuous low bleed natural gas pneumatic devices:</P>
                            <P>
                                (A) Indicate whether you measured emissions according to § 98.233(a)(3)(i)(A) or used default emission factors according to § 98.233(a)(3)(i)(B) to calculate emissions from your continuous high bleed and continuous low bleed natural 
                                <PRTPAGE P="42291"/>
                                gas pneumatic devices vented directly to the atmosphere.
                            </P>
                            <P>(B) If measurements were made according to § 98.233(a)(3)(i)(A), indicate the primary measurement method used (temporary flow meter, calibrated bagging, or high volume sampler).</P>
                            <P>(C) If default emission factors were used according to § 98.233(a)(3)(i)(B) to calculate emissions, report the following information for each type of applicable natural gas pneumatic device (continuous low bleed and continuous high bleed).</P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) Total number of natural gas pneumatic devices that vent directly to the atmosphere and that were not directly measured according to the requirements in § 98.233(a)(1) or (a)(2)(iii) (
                                <E T="03">i.e.,</E>
                                 “Count
                                <E T="52">t</E>
                                ” in equation W-1B to § 98.233).
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) The average estimated number of hours in the operating year that the natural gas pneumatic devices were in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) (“T
                                <E T="52">t</E>
                                ” in equation W-1B to § 98.233).
                            </P>
                            <P>(ii) For intermittent bleed natural gas pneumatic devices:</P>
                            <P>(A) Indicate the primary monitoring method used (OGI; Method 21 at 10,000 ppm; Method 21 at 500 ppm; or infrared laser beam) and the number of complete monitoring surveys conducted.</P>
                            <P>(B) The total number of intermittent bleed natural gas pneumatic devices detected as malfunctioning in any pneumatic device monitoring survey during the calendar year (“ × ” in equation W-1C to § 98.233).</P>
                            <P>
                                (C) Average time the intermittent bleed natural gas pneumatic devices were in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) and assumed to be malfunctioning in the calendar year (average value of “T
                                <E T="52">m.z</E>
                                ” in equation W-1C to § 98.233).
                            </P>
                            <P>(D) The total number of intermittent bleed natural gas pneumatic devices that were monitored but were not detected as malfunctioning in any pneumatic device monitoring survey during the calendar year (“Count” in equation W-1C to § 98.233).</P>
                            <P>
                                (E) Average time the intermittent bleed natural gas pneumatic devices that were monitored but were not detected as malfunctioning in any pneumatic device monitoring survey during the calendar year were in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) during the calendar year (“T
                                <E T="52">avg</E>
                                ” in equation W-1C to § 98.233).
                            </P>
                            <P>
                                (iii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for each type of natural gas pneumatic device calculated according to Calculation Method 3 in § 98.233(a)(3).
                            </P>
                            <P>
                                (iv) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for each type of natural gas pneumatic device calculated according to Calculation Method 3 in § 98.233(a)(3).
                            </P>
                            <P>(6) For natural gas pneumatic devices for which emissions were calculated using Calculation Method 4 according to § 98.233(a)(4), report the following information for each type of applicable natural gas pneumatic device (continuous low bleed, continuous high bleed, and intermittent bleed).</P>
                            <P>(i) [Reserved]</P>
                            <P>
                                (ii) The estimated average number of hours in the operating year that the natural gas pneumatic devices were in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) (“T
                                <E T="52">t</E>
                                ” in equation W-1B to § 98.233).
                            </P>
                            <P>
                                (iii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for the natural gas pneumatic devices combined, calculated according to Calculation Method 4 in § 98.233(a)(4).
                            </P>
                            <P>
                                (iv) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for the natural gas pneumatic devices combined, calculated according to Calculation Method 4 in § 98.233(a)(4).
                            </P>
                            <P>
                                (c) 
                                <E T="03">Natural gas driven pneumatic pumps.</E>
                                 You must indicate whether the facility has any natural gas driven pneumatic pumps. If the facility contains any natural gas driven pneumatic pumps, then you must report the information specified in paragraphs (c)(1) through (5) of this section.
                            </P>
                            <P>(1) [Reserved]</P>
                            <P>(2) The number of natural gas driven pneumatic pumps as specified in paragraphs (c)(2)(i) through (iv) of this section, as applicable.</P>
                            <P>(i) The total number of natural gas driven pneumatic pumps.</P>
                            <P>(ii) The total number of natural gas driven pneumatic pumps vented directly to the atmosphere at any point during the year.</P>
                            <P>(iii) [Reserved]</P>
                            <P>(iv) [Reserved]</P>
                            <P>(3) For natural gas driven pneumatic pumps for which vented emissions were calculated using Calculation Method 1 according to § 98.233(c)(1), report the information in paragraphs (c)(3)(i) through (vi) of this section for each measurement location.</P>
                            <P>(i) Unique measurement location identification number.</P>
                            <P>(ii) Type of flow monitor (volumetric flow monitor; mass flow monitor).</P>
                            <P>(iii) Number of natural gas driven pneumatic pumps downstream of the flow monitor.</P>
                            <P>(iv) An indication of whether any natural gas pneumatic devices are also downstream of the monitoring location.</P>
                            <P>
                                (v) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for the natural gas driven pneumatic pump(s) calculated according to § 98.233(c)(1) for the measurement location.
                            </P>
                            <P>
                                (vi) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for the natural gas driven pneumatic pump(s) calculated according to § 98.233(c)(1) for the measurement location.
                            </P>
                            <P>(4) If you used Calculation Method 2 according to § 98.233(c)(2) to calculate vented emissions, report the information in paragraphs (c)(4)(i) through (viii) of this section, as applicable.</P>
                            <P>(i) The number of years used in the current measurement cycle.</P>
                            <P>(ii) The total number of natural gas driven pneumatic pumps for which emissions were measured or calculated using Calculation Method 2.</P>
                            <P>(iii) Indicate whether the emissions from the natural gas driven pneumatic pumps at this facility were measured during the reporting year or if the emissions were calculated using equation W-2B to § 98.233.</P>
                            <P>(iv) If the natural gas driven pneumatic pumps at this facility were measured during the reporting year, indicate the primary measurement method used (temporary flow meter, calibrated bagging, or high volume sampler).</P>
                            <P>(v) If the emissions from natural gas driven pneumatic pumps at this facility were calculated using equation W-2B to § 98.233, report the following information:</P>
                            <P>(A) The value of the emission factor for the reporting year as calculated using equation W-2A to § 98.233 (in scf/hour/pump).</P>
                            <P>
                                (B) The total number of natural gas driven pneumatic pumps measured across all years upon which the emission factor is based (
                                <E T="03">i.e.,</E>
                                 the cumulative value of “Σ
                                <E T="54">n</E>
                                <E T="52">y=1</E>
                                  
                                <E T="03">Count</E>
                                <E T="54">y</E>
                                ” term used in equation W-2A to § 98.233).
                            </P>
                            <P>
                                (C) Total number of natural gas driven pneumatic pumps that vent directly to the atmosphere and that were not directly measured according to the requirements in § 98.233(c)(1) or (c)(2)(iii) (
                                <E T="03">i.e.,</E>
                                 “Count” in equation W-2B to § 98.233).
                            </P>
                            <P>
                                (D) The average estimated number of hours in the operating year the pumps were pumping liquid (
                                <E T="03">i.e.,</E>
                                 “T” in equation W-2B to § 98.233).
                            </P>
                            <P>
                                (vi) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , cumulative for all natural gas driven pneumatic pumps for which emissions were directly measured and calculated as specified in § 98.233(c)(2)(ii) through (vi). Enter 0 if emissions from none of the natural gas driven pneumatic pumps at this facility were measured during the reporting year.
                                <PRTPAGE P="42292"/>
                            </P>
                            <P>
                                (vii) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , cumulative for all natural gas driven pneumatic pumps for which emissions were directly measured and calculated as specified in § 98.233(c)(2)(ii) through (vi). Enter 0 if emissions from none of the natural gas driven pneumatic pumps at this facility were measured during the reporting year.
                            </P>
                            <P>
                                (viii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , cumulative for all natural gas driven pneumatic pumps for which emissions were calculated according to § 98.233(c)(2)(vii)(B) through (D). Enter 0 if emissions from all natural gas driven pneumatic pumps at this facility were measured during the reporting year.
                            </P>
                            <P>
                                (ix) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , cumulative for all natural gas driven pneumatic pumps for which emissions were calculated according to § 98.233(c)(2)(vii)(B) through (D). Enter 0 if emissions from all natural gas driven pneumatic pumps at this facility were measured during the reporting year.
                            </P>
                            <P>(5) If you used Calculation Method 3 according to § 98.233(c)(3) to calculate vented emissions, report the information in paragraphs (c)(5)(i) through (iv) of this section for the natural gas driven pneumatic pumps subject to Calculation Method 3.</P>
                            <P>
                                (i) Number of pumps that vent directly to the atmosphere (
                                <E T="03">i.e.,</E>
                                 “Count” in equation W-2B to § 98.233).
                            </P>
                            <P>(ii) Average estimated number of hours in the calendar year that natural gas driven pneumatic pumps that vented directly to atmosphere were pumping liquid (“T” in equation W-2B to § 98.233).</P>
                            <P>
                                (iii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for all natural gas driven pneumatic pumps vented directly to the atmosphere combined, calculated according to § 98.233(c)(3).
                            </P>
                            <P>
                                (iv) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for all natural gas driven pneumatic pumps vented directly to the atmosphere combined, calculated according to § 98.233(c)(3).
                            </P>
                            <P>(d) * * *</P>
                            <P>(2) * * *</P>
                            <P>
                                (iii) If you used Calculation Method 4 as specified in § 98.233(d) to calculate CO
                                <E T="52">2</E>
                                 emissions from the acid gas removal unit, then you must report the information specified in paragraphs (d)(2)(iii)(A) through (M) of this section, as applicable to the simulation software package used.
                            </P>
                            <STARS/>
                            <P>
                                (M) If a vent meter is installed and you elected to use Calculation Method 4 for an AGR, report the information in paragraphs (d)(2)(iii)(M)(
                                <E T="03">1</E>
                                ) through (
                                <E T="03">3</E>
                                ) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) The total annual volume of vent gas flowing out of the AGR in cubic feet per year at actual conditions as determined by flow meter (“V
                                <E T="52">a,meter</E>
                                ” from equation W-4D to § 98.233).
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) The total annual volume of vent gas flowing out of the AGR in cubic feet per year at actual conditions as determined the standard simulation software package (“V
                                <E T="52">a,sim</E>
                                ” from equation W-4D to § 98.233).
                            </P>
                            <P>
                                (
                                <E T="03">3</E>
                                ) If the calculated percent difference between the vent volumes (“PD” from equation W-4D to § 98.233) is greater than 20 percent, provide a brief description of the reason for the difference.
                            </P>
                            <P>
                                (e) 
                                <E T="03">Dehydrators.</E>
                                 You must indicate whether your facility contains any of the following equipment: Glycol dehydrators for which you calculated emissions using Calculation Method 1 according to § 98.233(e)(1), glycol dehydrators for which you calculated emissions using Calculation Method 2 according to § 98.233(e)(2), and dehydrators that use desiccant. If your facility contains any of the equipment listed in this paragraph (e), then you must report the applicable information in paragraphs (e)(1) through (3) of this section.
                            </P>
                            <P>(1) For each glycol dehydrator for which you calculated emissions using Calculation Method 1 (as specified in § 98.233(e)(1)), you must report the information specified in paragraphs (e)(1)(i) through (xviii) of this section for the dehydrator.</P>
                            <STARS/>
                            <P>(2) For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 million standard cubic feet per day for which you calculated emissions using Calculation Method 2 (as specified in § 98.233(e)(2)), you must report the information specified in paragraphs (e)(2)(i) through (v) of this section for the entire facility.</P>
                            <P>(i) The total number of dehydrators at the facility for which you calculated emissions using Calculation Method 2.</P>
                            <STARS/>
                            <P>(g) * * *</P>
                            <P>(5) If you used equation W-10A to § 98.233 to calculate annual volumetric total gas emissions, then you must report the information specified in paragraphs (g)(5)(i) through (iv) of this section.</P>
                            <STARS/>
                            <P>(iv) Whether the flow rate during the initial flowback period was determined using a multiphase flow meter upstream of the separator.</P>
                            <P>(6) If you used equation W-10B to § 98.233 to calculate annual volumetric total gas emissions, then you must report the information specified in paragraphs (g)(6)(i) through (iv) of this section.</P>
                            <STARS/>
                            <P>(iii) If a multiphase flowmeter was used to measure the flow rate during the initial flowback period, report the average flow rate measured by the multiphase flow meter from the initiation of flowback to the beginning of the period of time when sufficient quantities of gas present to enable separation in standard cubic feet per hour.</P>
                            <STARS/>
                            <P>(j) * * *</P>
                            <P>(2) * * *</P>
                            <P>(i) * * *</P>
                            <P>(A) The total annual oil/condensate throughput that is sent to all atmospheric tanks in the basin, in barrels. You may delay reporting of this data element for onshore production if you indicate in the annual report that wildcat wells and delineation wells are the only wells in the sub-basin with oil/condensate production that send oil/condensate to atmospheric tanks for which emissions were calculated using Calculation Method 3. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the total annual oil/condensate throughput from all wells and the well ID number(s) for the well(s) included in this volume.</P>
                            <STARS/>
                            <P>(m) * * *</P>
                            <P>
                                (4) Average gas to oil ratio, in standard cubic feet of gas per barrel of oil (average of the “GOR” values used in equation W-18 to § 98.233). Do not report GOR if you used a continuous flow monitor to determine the total volume of associated gas vented or routed to the flare (
                                <E T="03">i.e.,</E>
                                 if you did not use equation W-18 to § 98.233 for the well with associated gas venting or flaring emissions).
                            </P>
                            <P>
                                (5) Volume of oil produced, in barrels, in the calendar year during the time periods in which associated gas was vented or flared (the sum of “V
                                <E T="52">p,q</E>
                                ” used in equation W-18 to § 98.233). You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells from which associated gas was vented or flared. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the volume of oil produced for well(s) with associated gas venting and flaring and the well ID number(s) for the well(s) included in the 
                                <PRTPAGE P="42293"/>
                                measurement. Do not report the volume of oil produced if you used a continuous flow monitor to determine the total volume of associated gas vented or routed to the flare (
                                <E T="03">i.e.,</E>
                                 if you did not use equation W-18 to § 98.233 for the well with associated gas venting or flaring emissions).
                            </P>
                            <P>
                                (6) Total volume of associated gas sent to sales, in standard cubic feet, in the calendar year during time periods in which associated gas was vented or flared (the sum of “SG” values used in equation W-18 to § 98.233). You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells from which associated gas was vented or flared. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the measured total volume of associated gas sent to sales for well(s) with associated gas venting and flaring and the well ID number(s) for the well(s) included in the measurement. Do not report the volume of gas sent to sales if you used a continuous flow monitor to determine the total volume of associated gas vented or routed to the flare (
                                <E T="03">i.e.,</E>
                                 if you did not use equation W-18 to § 98.233).
                            </P>
                            <P>(7) * * *</P>
                            <P>(ii) If the associated gas volume vented from the well was measured using a continuous flow monitor, total volume of associated gas vented directly to the atmosphere, in standard cubic feet.</P>
                            <STARS/>
                            <P>
                                (o) 
                                <E T="03">Centrifugal compressors.</E>
                                 You must indicate whether your facility has centrifugal compressors. You must report the information specified in paragraphs (o)(1) and (2) of this section for all centrifugal compressors at your facility. For each compressor source or manifolded group of compressor sources that you conduct as found leak measurements as specified in § 98.233(o)(2) or (4), you must report the information specified in paragraph (o)(3) of this section. For each compressor source or manifolded group of compressor sources that you conduct continuous monitoring as specified in § 98.233(o)(3) or (5), you must report the information specified in paragraph (o)(4) of this section. Centrifugal compressors in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting that calculate emissions according to § 98.233(o)(10)(iii) are not required to report information in paragraphs (o)(1) through (4) of this section and instead must report the information specified in paragraph (o)(5) of this section.
                            </P>
                            <STARS/>
                            <P>
                                (p) 
                                <E T="03">Reciprocating compressors.</E>
                                 You must indicate whether your facility has reciprocating compressors. You must report the information specified in paragraphs (p)(1) and (2) of this section for all reciprocating compressors at your facility. For each compressor source or manifolded group of compressor sources that you conduct as found leak measurements as specified in § 98.233(p)(2) or (4), you must report the information specified in paragraph (p)(3) of this section. For each compressor source or manifolded group of compressor sources that you conduct continuous monitoring as specified in § 98.233(p)(3) or (5), you must report the information specified in paragraph (p)(4) of this section. Reciprocating compressors in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting that calculate emissions according to § 98.233(p)(10)(iii) are not required to report information in paragraphs (p)(1) through (4) of this section and instead must report the information specified in paragraph (p)(5) of this section.
                            </P>
                            <STARS/>
                            <P>(q) * * *</P>
                            <P>(1) You must report the information specified in paragraphs (q)(1)(i) through (vi) of this section.</P>
                            <STARS/>
                            <P>(vi) Report whether emissions were calculated using Calculation Method 1 (leaker factor emission calculation methodology) and/or using Calculation Method 2 (leaker measurement methodology).</P>
                            <P>(2) You must indicate whether your facility contains any of the component types subject to or complying with § 98.233(q) that are listed in § 98.232(c)(21), (d)(7), (e)(7) or (8), (f)(5) through (8), (g)(4), (g)(6) or (7), (h)(5), (h)(7) or (8), (i)(1), or (j)(10) for your facility's industry segment. For each component type that is located at your facility, you must report the information specified in paragraphs (q)(2)(i) through (v) of this section. If a component type is located at your facility and no leaks were identified from that component, then you must report the information in paragraphs (q)(2)(i) through (v) of this section but report a zero (“0”) for the information required according to paragraphs (q)(2)(ii) through (v) of this section. If you used Calculation Method 1 (leaker factor emission calculation methodology) for some complete leak surveys and used Calculation Method 2 (leaker measurement methodology) for some complete leak surveys, you must report the information specified in paragraphs (q)(2)(i) through (ix) of this section separately for component surveys using Calculation Method 1 and Calculation Method 2.</P>
                            <P>(i) [Reserved]</P>
                            <P>(ii) Component type.</P>
                            <P>(iii) [Reserved]</P>
                            <P>
                                (iv) Emission factor or measurement method used (
                                <E T="03">e.g.,</E>
                                 default emission factor; facility-specific emission factor developed according to § 98.233(q)(4); or direct measurement according to § 98.233(q)(3)).
                            </P>
                            <P>(v) Total number of components surveyed by type in the calendar year.</P>
                            <P>
                                (vi) Total number of the surveyed component type that were identified as leaking in the calendar year (“x
                                <E T="52">p</E>
                                ” in equation W-30 to § 98.233 for the component type or the number of leaks measured for the specified component type according to the provisions in § 98.233(q)(3)).
                            </P>
                            <P>
                                (vii) Average time the surveyed components are assumed to be leaking and operational, in hours (average of “T
                                <E T="52">p,z</E>
                                ” from equation W-30 to § 98.233 for the component type or average duration of leaks for the specified component type determined according to the provisions in § 98.233(q)(3)(ii))).
                            </P>
                            <P>
                                (viii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for the component type as calculated using equation W-30 to § 98.233 or § 98.233(q)(3)(vii) (for surveyed components only).
                            </P>
                            <P>
                                (ix) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for the component type as calculated using equation W-30 to § 98.233 or § 98.233(q)(3)(vii) (for surveyed components only).
                            </P>
                            <STARS/>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>17. Revise and republish § 98.236 to read as follows:</AMDPAR>
                        <SECTION>
                            <SECTNO>§ 98.236</SECTNO>
                            <SUBJECT>Data reporting requirements.</SUBJECT>
                            <P>In addition to the information required by § 98.3(c), each annual report must contain reported emissions and related information as specified in this section. Reporters that use a flow or volume measurement system that corrects to standard conditions as provided in the introductory text in § 98.233 for data elements that are otherwise required to be determined at actual conditions, report gas volumes at standard conditions rather than the gas volumes at actual conditions and report the standard temperature and pressure used by the measurement system rather than the actual temperature and pressure.</P>
                            <P>
                                (a) The annual report must include the information specified in paragraphs (a)(1) through (10) of this section for 
                                <PRTPAGE P="42294"/>
                                each applicable industry segment. The annual report must also include annual emissions totals, in metric tons of each GHG, for each applicable industry segment listed in paragraphs (a)(1) through (10) of this section, and each applicable emission source listed in paragraphs (b) through (z), (dd) and (ee) of this section.
                            </P>
                            <P>
                                (1) 
                                <E T="03">Onshore petroleum and natural gas production.</E>
                                 For the equipment/activities specified in paragraphs (a)(1)(i) through (xxii) of this section, report the information specified in the applicable paragraphs of this section.
                            </P>
                            <P>
                                (i) 
                                <E T="03">Natural gas pneumatic devices.</E>
                                 Report the information specified in paragraph (b) of this section.
                            </P>
                            <P>
                                (ii) 
                                <E T="03">Natural gas driven pneumatic pumps.</E>
                                 Report the information specified in paragraph (c) of this section.
                            </P>
                            <P>
                                (iii) 
                                <E T="03">Acid gas removal units and nitrogen removal units.</E>
                                 Report the information specified in paragraph (d) of this section.
                            </P>
                            <P>
                                (iv) 
                                <E T="03">Dehydrators.</E>
                                 Report the information specified in paragraph (e) of this section.
                            </P>
                            <P>
                                (v) 
                                <E T="03">Liquids unloading.</E>
                                 Report the information specified in paragraph (f) of this section.
                            </P>
                            <P>
                                (vi) 
                                <E T="03">Completions and workovers with hydraulic fracturing.</E>
                                 Report the information specified in paragraph (g) of this section.
                            </P>
                            <P>
                                (vii) 
                                <E T="03">Completions and workovers without hydraulic fracturing.</E>
                                 Report the information specified in paragraph (h) of this section.
                            </P>
                            <P>
                                (viii) 
                                <E T="03">Blowdown vent stacks.</E>
                                 Report the information specified in paragraph (i) of this section.
                            </P>
                            <P>
                                (ix) 
                                <E T="03">Hydrocarbon liquids and produced water storage tanks.</E>
                                 Report the information specified in paragraph (j) of this section.
                            </P>
                            <P>
                                (x) 
                                <E T="03">Well testing.</E>
                                 Report the information specified in paragraph (l) of this section.
                            </P>
                            <P>
                                (xi) 
                                <E T="03">Associated natural gas.</E>
                                 Report the information specified in paragraph (m) of this section.
                            </P>
                            <P>
                                (xii) 
                                <E T="03">Flare stacks.</E>
                                 Report the information specified in paragraph (n) of this section.
                            </P>
                            <P>
                                (xiii) 
                                <E T="03">Centrifugal compressors.</E>
                                 Report the information specified in paragraph (o) of this section.
                            </P>
                            <P>
                                (xiv) 
                                <E T="03">Reciprocating compressors.</E>
                                 Report the information specified in paragraph (p) of this section.
                            </P>
                            <P>
                                (xv) 
                                <E T="03">Equipment leak surveys.</E>
                                 Report the information specified in paragraph (q) of this section.
                            </P>
                            <P>
                                (xvi) 
                                <E T="03">Equipment leaks by population count.</E>
                                 Report the information specified in paragraph (r) of this section.
                            </P>
                            <P>
                                (xvii) 
                                <E T="03">EOR injection pumps.</E>
                                 Report the information specified in paragraph (w) of this section.
                            </P>
                            <P>
                                (xviii) 
                                <E T="03">EOR hydrocarbon liquids.</E>
                                 Report the information specified in paragraph (x) of this section.
                            </P>
                            <P>
                                (xix) 
                                <E T="03">Other large release events.</E>
                                 Report the information specified in paragraph (y) of this section.
                            </P>
                            <P>
                                (xx) 
                                <E T="03">Combustion equipment.</E>
                                 Report the information specified in paragraph (z) of this section.
                            </P>
                            <P>
                                (xxi) 
                                <E T="03">Drilling mud degassing.</E>
                                 Report the information specified in paragraph (dd) of this section.
                            </P>
                            <P>
                                (xxii) 
                                <E T="03">Crankcase vents.</E>
                                 Reporting the information specified in paragraph (ee) of this section.
                            </P>
                            <P>
                                (2) 
                                <E T="03">Offshore petroleum and natural gas production.</E>
                                 For the equipment/activities specified in paragraphs (a)(2)(i) and (ii) of this section, report the information specified in the applicable paragraphs of this section.
                            </P>
                            <P>
                                (i) 
                                <E T="03">Offshore petroleum and natural gas production.</E>
                                 Report the information specified in paragraph (s) of this section.
                            </P>
                            <P>
                                (ii) 
                                <E T="03">Other large release events.</E>
                                 Report the information specified in paragraph (y) of this section.
                            </P>
                            <P>
                                (3) 
                                <E T="03">Onshore natural gas processing.</E>
                                 For the equipment/activities specified in paragraphs (a)(3)(i) through (xi) of this section, report the information specified in the applicable paragraphs of this section.
                            </P>
                            <P>
                                (i) 
                                <E T="03">Natural gas pneumatic devices.</E>
                                 Report the information specified in paragraph (b) of this section.
                            </P>
                            <P>
                                (ii) 
                                <E T="03">Acid gas removal units and nitrogen removal units.</E>
                                 Report the information specified in paragraph (d) of this section.
                            </P>
                            <P>
                                (iii) 
                                <E T="03">Dehydrators.</E>
                                 Report the information specified in paragraph (e) of this section.
                            </P>
                            <P>
                                (iv) 
                                <E T="03">Blowdown vent stacks.</E>
                                 Report the information specified in paragraph (i) of this section.
                            </P>
                            <P>
                                (v) 
                                <E T="03">Hydrocarbon liquids and produced water storage tanks.</E>
                                 Report the information specified in paragraph (j) of this section.
                            </P>
                            <P>
                                (vi) 
                                <E T="03">Flare stacks.</E>
                                 Report the information specified in paragraph (n) of this section.
                            </P>
                            <P>
                                (vii) 
                                <E T="03">Centrifugal compressors.</E>
                                 Report the information specified in paragraph (o) of this section.
                            </P>
                            <P>
                                (viii) 
                                <E T="03">Reciprocating compressors.</E>
                                 Report the information specified in paragraph (p) of this section.
                            </P>
                            <P>
                                (ix) 
                                <E T="03">Equipment leak surveys.</E>
                                 Report the information specified in paragraph (q) of this section.
                            </P>
                            <P>
                                (x) 
                                <E T="03">Other large release events.</E>
                                 Report the information specified in paragraph (y) of this section.
                            </P>
                            <P>
                                (xi) 
                                <E T="03">Crankcase vents.</E>
                                 Report the information specified in paragraph (ee) of this section.
                            </P>
                            <P>
                                (4) 
                                <E T="03">Onshore natural gas transmission compression.</E>
                                 For the equipment/activities specified in paragraphs (a)(4)(i) through (x) of this section, report the information specified in the applicable paragraphs of this section.
                            </P>
                            <P>
                                (i) 
                                <E T="03">Natural gas pneumatic devices.</E>
                                 Report the information specified in paragraph (b) of this section.
                            </P>
                            <P>
                                (ii) 
                                <E T="03">Dehydrators.</E>
                                 Report the information specified in paragraph (e) of this section.
                            </P>
                            <P>
                                (iii) 
                                <E T="03">Blowdown vent stacks.</E>
                                 Report the information specified in paragraph (i) of this section.
                            </P>
                            <P>
                                (iv) 
                                <E T="03">Condensate storage tanks.</E>
                                 Report the information specified in paragraph (k) of this section.
                            </P>
                            <P>
                                (v) 
                                <E T="03">Flare stacks.</E>
                                 Report the information specified in paragraph (n) of this section.
                            </P>
                            <P>
                                (vi) 
                                <E T="03">Centrifugal compressors.</E>
                                 Report the information specified in paragraph (o) of this section.
                            </P>
                            <P>
                                (vii) 
                                <E T="03">Reciprocating compressors.</E>
                                 Report the information specified in paragraph (p) of this section.
                            </P>
                            <P>
                                (viii) 
                                <E T="03">Equipment leak surveys.</E>
                                 Report the information specified in paragraph (q) of this section.
                            </P>
                            <P>
                                (ix) 
                                <E T="03">Other large release events.</E>
                                 Report the information specified in paragraph (y) of this section.
                            </P>
                            <P>
                                (x) 
                                <E T="03">Crankcase vents.</E>
                                 Reporting the information specified in paragraph (ee) of this section.
                            </P>
                            <P>
                                (5) 
                                <E T="03">Underground natural gas storage.</E>
                                 For the equipment/activities specified in paragraphs (a)(5)(i) through (xi) of this section, report the information specified in the applicable paragraphs of this section.
                            </P>
                            <P>
                                (i) 
                                <E T="03">Natural gas pneumatic devices.</E>
                                 Report the information specified in paragraph (b) of this section.
                            </P>
                            <P>
                                (ii) 
                                <E T="03">Dehydrators.</E>
                                 Report the information specified in paragraph (e) of this section.
                            </P>
                            <P>
                                (iii) 
                                <E T="03">Blowdown vent stacks.</E>
                                 Report the information specified in paragraph (i) of this section.
                            </P>
                            <P>
                                (iv) 
                                <E T="03">Condensate storage tanks.</E>
                                 Report the information specified in paragraph (k) of this section.
                            </P>
                            <P>
                                (v) 
                                <E T="03">Flare stacks.</E>
                                 Report the information specified in paragraph (n) of this section.
                            </P>
                            <P>
                                (vi) 
                                <E T="03">Centrifugal compressors.</E>
                                 Report the information specified in paragraph (o) of this section.
                            </P>
                            <P>
                                (vii) 
                                <E T="03">Reciprocating compressors.</E>
                                 Report the information specified in paragraph (p) of this section.
                            </P>
                            <P>
                                (viii) 
                                <E T="03">Equipment leak surveys.</E>
                                 Report the information specified in paragraph (q) of this section.
                            </P>
                            <P>
                                (ix) 
                                <E T="03">Equipment leaks by population count.</E>
                                 Report the information specified in paragraph (r) of this section.
                            </P>
                            <P>
                                (x) 
                                <E T="03">Other large release events.</E>
                                 Report the information specified in paragraph (y) of this section.
                                <PRTPAGE P="42295"/>
                            </P>
                            <P>
                                (xi) 
                                <E T="03">Crankcase vents.</E>
                                 Reporting the information specified in paragraph (ee) of this section.
                            </P>
                            <P>
                                (6) 
                                <E T="03">LNG storage.</E>
                                 For the equipment/activities specified in paragraphs (a)(6)(i) through (ix) of this section, report the information specified in the applicable paragraphs of this section.
                            </P>
                            <P>
                                (i) 
                                <E T="03">Acid gas removal units and nitrogen removal units.</E>
                                 Report the information specified in paragraph (d) of this section.
                            </P>
                            <P>
                                (ii) 
                                <E T="03">Blowdown vent stacks.</E>
                                 Report the information specified in paragraph (i) of this section.
                            </P>
                            <P>
                                (iii) 
                                <E T="03">Flare stacks.</E>
                                 Report the information specified in paragraph (n) of this section.
                            </P>
                            <P>
                                (iv) 
                                <E T="03">Centrifugal compressors.</E>
                                 Report the information specified in paragraph (o) of this section.
                            </P>
                            <P>
                                (v) 
                                <E T="03">Reciprocating compressors.</E>
                                 Report the information specified in paragraph (p) of this section.
                            </P>
                            <P>
                                (vi) 
                                <E T="03">Equipment leak surveys.</E>
                                 Report the information specified in paragraph (q) of this section.
                            </P>
                            <P>
                                (vii) 
                                <E T="03">Equipment leaks by population count.</E>
                                 Report the information specified in paragraph (r) of this section.
                            </P>
                            <P>
                                (viii) 
                                <E T="03">Other large release events.</E>
                                 Report the information specified in paragraph (y) of this section.
                            </P>
                            <P>
                                (ix) 
                                <E T="03">Crankcase vents.</E>
                                 Reporting the information specified in paragraph (ee) of this section.
                            </P>
                            <P>
                                (7) 
                                <E T="03">LNG import and export equipment.</E>
                                 For the equipment/activities specified in paragraphs (a)(7)(i) through (ix) of this section, report the information specified in the applicable paragraphs of this section.
                            </P>
                            <P>
                                (i) 
                                <E T="03">Acid gas removal units and nitrogen removal units.</E>
                                 Report the information specified in paragraph (d) of this section.
                            </P>
                            <P>
                                (ii) 
                                <E T="03">Blowdown vent stacks.</E>
                                 Report the information specified in paragraph (i) of this section.
                            </P>
                            <P>
                                (iii) 
                                <E T="03">Flare stacks.</E>
                                 Report the information specified in paragraph (n) of this section.
                            </P>
                            <P>
                                (iv) 
                                <E T="03">Centrifugal compressors.</E>
                                 Report the information specified in paragraph (o) of this section.
                            </P>
                            <P>
                                (v) 
                                <E T="03">Reciprocating compressors.</E>
                                 Report the information specified in paragraph (p) of this section.
                            </P>
                            <P>
                                (vi) 
                                <E T="03">Equipment leak surveys.</E>
                                 Report the information specified in paragraph (q) of this section.
                            </P>
                            <P>
                                (vii) 
                                <E T="03">Equipment leaks by population count.</E>
                                 Report the information specified in paragraph (r) of this section.
                            </P>
                            <P>
                                (viii) 
                                <E T="03">Other large release events.</E>
                                 Report the information specified in paragraph (y) of this section.
                            </P>
                            <P>
                                (ix) 
                                <E T="03">Crankcase vents.</E>
                                 Reporting the information specified in paragraph (ee) of this section.
                            </P>
                            <P>
                                (8) 
                                <E T="03">Natural gas distribution.</E>
                                 For the equipment/activities specified in paragraphs (a)(8)(i) through (vii) of this section, report the information specified in the applicable paragraphs of this section.
                            </P>
                            <P>
                                (i) 
                                <E T="03">Natural gas pneumatic devices.</E>
                                 Report the information specified in paragraph (b) of this section.
                            </P>
                            <P>
                                (ii) 
                                <E T="03">Blowdown vent stacks.</E>
                                 Report the information specified in paragraph (i) of this section.
                            </P>
                            <P>
                                (iii) 
                                <E T="03">Equipment leak surveys.</E>
                                 Report the information specified in paragraph (q) of this section.
                            </P>
                            <P>
                                (iv) 
                                <E T="03">Equipment leaks by population count.</E>
                                 Report the information specified in paragraph (r) of this section.
                            </P>
                            <P>
                                (v) 
                                <E T="03">Other large release events.</E>
                                 Report the information specified in paragraph (y) of this section.
                            </P>
                            <P>
                                (vi) 
                                <E T="03">Combustion equipment.</E>
                                 Report the information specified in paragraph (z) of this section.
                            </P>
                            <P>
                                (vii) 
                                <E T="03">Crankcase vents.</E>
                                 Reporting the information specified in paragraph (ee) of this section.
                            </P>
                            <P>
                                (9) 
                                <E T="03">Onshore petroleum and natural gas gathering and boosting.</E>
                                 For the equipment/activities specified in paragraphs (a)(9)(i) through (xiv) of this section, report the information specified in the applicable paragraphs of this section.
                            </P>
                            <P>
                                (i) 
                                <E T="03">Natural gas pneumatic devices.</E>
                                 Report the information specified in paragraph (b) of this section.
                            </P>
                            <P>
                                (ii) 
                                <E T="03">Natural gas driven pneumatic pumps.</E>
                                 Report the information specified in paragraph (c) of this section.
                            </P>
                            <P>
                                (iii) 
                                <E T="03">Acid gas removal units and nitrogen removal units.</E>
                                 Report the information specified in paragraph (d) of this section.
                            </P>
                            <P>
                                (iv) 
                                <E T="03">Dehydrators.</E>
                                 Report the information specified in paragraph (e) of this section.
                            </P>
                            <P>
                                (v) 
                                <E T="03">Blowdown vent stacks.</E>
                                 Report the information specified in paragraph (i) of this section.
                            </P>
                            <P>
                                (vi) 
                                <E T="03">Hydrocarbon liquids and produced water storage tanks.</E>
                                 Report the information specified in paragraph (j) of this section.
                            </P>
                            <P>
                                (vii) 
                                <E T="03">Flare stacks.</E>
                                 Report the information specified in paragraph (n) of this section.
                            </P>
                            <P>
                                (viii) 
                                <E T="03">Centrifugal compressors.</E>
                                 Report the information specified in paragraph (o) of this section.
                            </P>
                            <P>
                                (ix) 
                                <E T="03">Reciprocating compressors.</E>
                                 Report the information specified in paragraph (p) of this section.
                            </P>
                            <P>
                                (x) 
                                <E T="03">Equipment leak surveys.</E>
                                 Report the information specified in paragraph (q) of this section.
                            </P>
                            <P>
                                (xi) 
                                <E T="03">Equipment leaks by population count.</E>
                                 Report the information specified in paragraph (r) of this section.
                            </P>
                            <P>
                                (xii) 
                                <E T="03">Other large release events.</E>
                                 Report the information specified in paragraph (y) of this section.
                            </P>
                            <P>
                                (xiii) 
                                <E T="03">Combustion equipment.</E>
                                 Report the information specified in paragraph (z) of this section.
                            </P>
                            <P>
                                (xiv) 
                                <E T="03">Crankcase vents.</E>
                                 Reporting the information specified in paragraph (ee) of this section.
                            </P>
                            <P>
                                (10) 
                                <E T="03">Onshore natural gas transmission pipeline.</E>
                                 For the equipment/activities specified in paragraphs (a)(10)(i) through (iii) of this section, report the information specified in the applicable paragraphs of this section.
                            </P>
                            <P>
                                (i) 
                                <E T="03">Blowdown vent stacks.</E>
                                 Report the information specified in paragraph (i) of this section.
                            </P>
                            <P>
                                (ii) 
                                <E T="03">Equipment leaks by population count.</E>
                                 Report the information specified in paragraph (r) of this section.
                            </P>
                            <P>
                                (iii) 
                                <E T="03">Other large release events.</E>
                                 Report the information specified in paragraph (y) of this section.
                            </P>
                            <P>
                                (b) 
                                <E T="03">Natural gas pneumatic devices.</E>
                                 You must indicate whether the facility contains the following types of equipment: Continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, and intermittent bleed natural gas pneumatic devices. If the facility contains any continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, or intermittent bleed natural gas pneumatic devices, then you must report the information specified in paragraphs (b)(1) through (6) of this section, as applicable. You must report the information specified in paragraphs (b)(1) through (6) of this section, as applicable, for each well-pad (for onshore petroleum and natural gas production), each gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments).
                            </P>
                            <P>(1) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(2) The number of natural gas pneumatic devices as specified in paragraphs (b)(2)(i) through (viii) of this section, as applicable. If a natural gas pneumatic device was vented directly to the atmosphere for part of the year and routed to a flare, combustion unit, or vapor recovery system during another part of the year, then include the device in each of the applicable counts specified in paragraphs (b)(2)(ii) through (vii) of this section.</P>
                            <P>
                                (i) The total number of natural gas pneumatic devices of each type 
                                <PRTPAGE P="42296"/>
                                (continuous low bleed, continuous high bleed, and intermittent bleed), determined according to § 98.233(a)(5) through (7).
                            </P>
                            <P>(ii) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere, determined according to § 98.233(a)(5) through (7).</P>
                            <P>(iii) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) routed to a flare, combustion, or vapor recovery system.</P>
                            <P>(iv) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere for which emissions were calculated using Calculation Method 1 according to § 98.233(a)(1).</P>
                            <P>(v) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere for which emissions were calculated using Calculation Method 2 according to § 98.233(a)(2).</P>
                            <P>(vi) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere for which emissions were calculated using Calculation Method 3 according to § 98.233(a)(3).</P>
                            <P>(vii) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere for which emissions were calculated using Calculation Method 4 according to § 98.233(a)(4).</P>
                            <P>(viii) If the reported values in paragraphs (b)(2)(i) through (vii) of this section are estimated values determined according to § 98.233(a)(6), then you must report the information specified in paragraphs (b)(2)(viii)(A) through (C) of this section.</P>
                            <P>(A) The number of natural gas pneumatic devices of each type reported in paragraphs (b)(2)(i) through (vii) of this section that are counted.</P>
                            <P>(B) The number of natural gas pneumatic devices of each type reported in paragraphs (b)(2)(i) through (vii) of this section that are estimated (not counted).</P>
                            <P>(C) Whether the calendar year is the first calendar year of reporting or the second calendar year of reporting.</P>
                            <P>(3) For natural gas pneumatic devices vented directly to the atmosphere for which emissions were calculated using Calculation Method 1 according to § 98.233(a)(1), report the information in paragraphs (b)(3)(i) through (vi) of this section for each measurement location.</P>
                            <P>(i) Unique measurement location identification number.</P>
                            <P>(ii) Type of flow monitor (volumetric flow monitor; mass flow monitor).</P>
                            <P>(iii) Number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) downstream of the flow monitor.</P>
                            <P>(iv) An indication of whether a natural gas driven pneumatic pump is also downstream of the flow monitor.</P>
                            <P>
                                (v) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for the natural gas pneumatic devices calculated according to § 98.233(a)(1) for the measurement location.
                            </P>
                            <P>
                                (vi) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for the natural gas pneumatic devices calculated according to § 98.233(a)(1) for the measurement location.
                            </P>
                            <P>(4) For natural gas pneumatic devices vented directly to the atmosphere for which emissions were calculated using Calculation Method 2 according to § 98.233(a)(2), report the information in paragraphs (b)(4)(i) through (ii) of this section, as applicable.</P>
                            <P>(i) For onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities:</P>
                            <P>(A) Indicate the primary measurement method used (temporary flow meter, calibrated bagging, or high volume sampler).</P>
                            <P>
                                (B) The average number of hours each type of the natural gas pneumatic device (continuous low bleed, continuous high bleed, and intermittent bleed) was in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) in the calendar year.
                            </P>
                            <P>
                                (C) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , cumulative by type of natural gas pneumatic device for which emissions were directly measured and calculated as specified in § 98.233(a)(2)(iii) through (viii).
                            </P>
                            <P>
                                (D) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , cumulative by type of natural gas pneumatic device for which emissions were directly measured and calculated as specified in § 98.233(a)(2)(iii) through (viii).
                            </P>
                            <P>(ii) For onshore natural gas processing facilities, onshore natural gas transmission compression facilities, underground natural gas storage facilities, and natural gas distribution facilities:</P>
                            <P>(A) The number of years used in the current measurement cycle.</P>
                            <P>(B) Indicate the primary measurement method used (temporary flow meter, calibrated bagging, or high volume sampler) to measure the emissions from natural gas pneumatic devices at this facility.</P>
                            <P>(C) Indicate whether the emissions from any natural gas pneumatic devices at this facility were calculated using equation W-1B to § 98.233.</P>
                            <P>(D) If the emissions from any natural gas pneumatic devices at this facility were calculated using equation W-1B to § 98.233, report the following information for each type of natural gas pneumatic device (continuous low bleed, continuous high bleed, and intermittent bleed).</P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) The value of the emission factor for the reporting year as calculated using equation W-1A to § 98.233 (in scf/hour/device).
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) The total number of natural gas pneumatic devices measured across all years upon which the emission factor is based (
                                <E T="03">i.e.,</E>
                                 the cumulative value of “Σ
                                <E T="03">y</E>
                                =1
                                <E T="53">n</E>
                                  
                                <E T="03">Count</E>
                                <E T="54">t,y</E>
                                ” in equation W-1A to § 98.233).
                            </P>
                            <P>
                                (
                                <E T="03">3</E>
                                ) Total number of natural gas pneumatic devices that vent directly to the atmosphere and that were not directly measured according to the requirements in § 98.233(a)(1) or (a)(2)(iii) (
                                <E T="03">i.e.,</E>
                                 “Count
                                <E T="52">t</E>
                                ” in equation W-1B to § 98.233).
                            </P>
                            <P>
                                (
                                <E T="03">4</E>
                                ) The average estimated number of hours in the operating year the natural gas pneumatic devices were in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) (“T
                                <E T="52">t</E>
                                ” in equation W-1B to § 98.233).
                            </P>
                            <P>
                                (E) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , cumulative by type of natural gas pneumatic device for which emissions were directly measured and calculated as specified in § 98.233(a)(2)(iii) through (viii).
                            </P>
                            <P>
                                (F) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , cumulative by type of natural gas pneumatic device for which emissions were directly measured and calculated as specified in § 98.233(a)(2)(iii) through (viii).
                            </P>
                            <P>
                                (G) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , cumulative by type of natural gas pneumatic device for which emissions were calculated according to § 98.233(a)(2)(ix). Enter 0 if all devices at this facility were monitored during the reporting year.
                            </P>
                            <P>
                                (H) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , cumulative by type of natural gas pneumatic device for which emissions were calculated according to § 98.233(a)(2)(ix). Enter 0 if all devices at this facility were monitored during the reporting year.
                            </P>
                            <P>
                                (5) For natural gas pneumatic devices vented directly to the atmosphere for which emissions were calculated using 
                                <PRTPAGE P="42297"/>
                                Calculation Method 3 according to § 98.233(a)(3), report the information in paragraphs (b)(5)(i) through (iv) of this section.
                            </P>
                            <P>(i) For continuous high bleed and continuous low bleed natural gas pneumatic devices:</P>
                            <P>(A) Indicate whether you measured emissions according to § 98.233(a)(3)(i)(A) or used default emission factors according to § 98.233(a)(3)(i)(B) to calculate emissions from your continuous high bleed and continuous low bleed natural gas pneumatic devices vented directly to the atmosphere at this well-pad, gathering and boosting site, or facility, as applicable.</P>
                            <P>(B) If measurements were made according to § 98.233(a)(3)(i)(A), indicate the primary measurement method used (temporary flow meter, calibrated bagging, or high volume sampler).</P>
                            <P>(C) If default emission factors were used according to § 98.233(a)(3)(i)(B) to calculate emissions, report the following information for each type of applicable natural gas pneumatic device (continuous low bleed and continuous high bleed).</P>
                            <P>
                                (1) Total number of natural gas pneumatic devices that vent directly to the atmosphere and that were not directly measured according to the requirements in § 98.233(a)(1) or (a)(2)(iii) (“Count
                                <E T="52">t</E>
                                ” in equation W-1B to § 98.233).
                            </P>
                            <P>
                                (2) The average estimated number of hours in the operating year that the natural gas pneumatic devices were in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) (“T
                                <E T="52">t</E>
                                ” in equation W-1B to § 98.233).
                            </P>
                            <P>(ii) For intermittent bleed natural gas pneumatic devices:</P>
                            <P>(A) Indicate the primary monitoring method used (OGI; Method 21 at 10,000 ppm; Method 21 at 500 ppm; or infrared laser beam) and the number of complete monitoring surveys conducted at the well-pad site or gathering and boosting site.</P>
                            <P>(B) The total number of intermittent bleed natural gas pneumatic devices detected as malfunctioning in any pneumatic device monitoring survey during the calendar year (“x” in equation W-1C to § 98.233).</P>
                            <P>
                                (C) Average time the intermittent bleed natural gas pneumatic devices were in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) and assumed to be malfunctioning in the calendar year (average value of “T
                                <E T="52">m.z</E>
                                ” in equation W-1C to § 98.233).
                            </P>
                            <P>(D) The total number of intermittent bleed natural gas pneumatic devices that were monitored but were not detected as malfunctioning in any pneumatic device monitoring survey during the calendar year (“Count” in equation W-1C to § 98.233).</P>
                            <P>
                                (E) Average time the intermittent bleed natural gas pneumatic devices that were monitored but were not detected as malfunctioning in any pneumatic device monitoring survey during the calendar year were in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) during the calendar year (“T
                                <E T="52">avg</E>
                                ” in equation W-1C to § 98.233).
                            </P>
                            <P>
                                (iii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for each type of natural gas pneumatic device calculated according to Calculation Method 3 in § 98.233(a)(3).
                            </P>
                            <P>
                                (iv) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for each type of natural gas pneumatic device calculated according to Calculation Method 3 in § 98.233(a)(3).
                            </P>
                            <P>(6) For natural gas pneumatic devices vented directly to the atmosphere for which emissions were calculated using Calculation Method 4 according to § 98.233(a)(4), report the following information for each type of applicable natural gas pneumatic device (continuous low bleed, continuous high bleed, and intermittent bleed).</P>
                            <P>
                                (i) Total number of natural gas pneumatic devices that vent directly to the atmosphere and that were not directly measured according to the requirements in § 98.233(a)(1) (
                                <E T="03">i.e.,</E>
                                 “Count
                                <E T="52">t</E>
                                ” in equation W-1B to § 98.233).
                            </P>
                            <P>
                                (ii) The average estimated number of hours in the operating year that the natural gas pneumatic devices were in service (
                                <E T="03">i.e.,</E>
                                 supplied with natural gas) (“T
                                <E T="52">t</E>
                                ” in equation W-1B to § 98.233).
                            </P>
                            <P>
                                (iii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for each type of natural gas pneumatic device calculated according to Calculation Method 4 in § 98.233(a)(4).
                            </P>
                            <P>
                                (iv) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for each type of natural gas pneumatic device calculated according to Calculation Method 4 in § 98.233(a)(4).
                            </P>
                            <P>
                                (c) 
                                <E T="03">Natural gas driven pneumatic pumps.</E>
                                 You must indicate whether the facility has any natural gas driven pneumatic pumps. If the facility contains any natural gas driven pneumatic pumps, then you must report the information specified in paragraphs (c)(1) through (5) of this section. You must report the information specified in paragraphs (c)(1) through (5) of this section, as applicable, for each well-pad site (for onshore petroleum and natural gas production) and each gathering and boosting site (for onshore petroleum and natural gas gathering and boosting).
                            </P>
                            <P>(1) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(2) The number of natural gas driven pneumatic pumps as specified in paragraphs (c)(2)(i) through (iv) of this section, as applicable. If a natural gas driven pneumatic pump was vented directly to the atmosphere for part of the year and routed to a flare, combustion, or vapor recovery system during another part of the year, then include the device in each of the applicable counts specified in paragraphs (c)(2)(ii) through (iv) of this section.</P>
                            <P>(i) The total number of natural gas driven pneumatic pumps.</P>
                            <P>(ii) The total number of natural gas driven pneumatic pumps vented directly to the atmosphere at any point during the year (including pumps that normally routed emissions to a flare but flow bypassed the flare for part of the year).</P>
                            <P>(iii) The total number of natural gas driven pneumatic pumps routed to a flare at any point during the year.</P>
                            <P>(iv) The total number of natural gas driven pneumatic pumps routed to combustion or a vapor recovery system at any point during the year.</P>
                            <P>(3) For natural gas driven pneumatic pumps for which vented emissions were calculated using Calculation Method 1 according to § 98.233(c)(1), report the information in paragraphs (c)(3)(i) through (vi) of this section for each measurement location.</P>
                            <P>(i) Unique measurement location identification number.</P>
                            <P>(ii) Type of flow monitor (volumetric flow monitor; mass flow monitor).</P>
                            <P>(iii) Number of natural gas driven pneumatic pumps downstream of the flow monitor.</P>
                            <P>(iv) An indication of whether any natural gas pneumatic devices are also downstream of the monitoring location.</P>
                            <P>
                                (v) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for the pneumatic pump(s) calculated according to § 98.233(c)(1) for the measurement location.
                            </P>
                            <P>
                                (vi) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for the pneumatic pump(s) calculated according to § 98.233(c)(1) for the measurement location.
                            </P>
                            <P>(4) If you used Calculation Method 2 according to § 98.233(c)(2) to calculate vented emissions, report the information in paragraphs (c)(4)(i) through (ix) of this section, as applicable.</P>
                            <P>(i) The number of years used in the current measurement cycle.</P>
                            <P>
                                (ii) The total number of natural gas driven pneumatic pumps for which emissions were measured or calculated using Calculation Method 2.
                                <PRTPAGE P="42298"/>
                            </P>
                            <P>(iii) Indicate whether the emissions from the natural gas driven pneumatic pumps at this well-pad site or gathering and boosting site, as applicable, were measured during the reporting year or if the emissions were calculated using equation W-2B to § 98.233.</P>
                            <P>(iv) If the natural gas driven pneumatic pumps at this well-pad site or gathering and boosting site, as applicable, were measured during the reporting year, indicate the primary measurement method used (temporary flow meter, calibrated bagging, or high volume sampler).</P>
                            <P>(v) If the emissions from natural gas driven pneumatic pumps at this well-pad site or gathering and boosting site, as applicable, were calculated using equation W-2B to § 98.233, report the following information:</P>
                            <P>(A) The value of the emission factor for the reporting year as calculated using equation W-2A to § 98.233 (in scf/hour/pump).</P>
                            <P>
                                (B) The total number of natural gas driven pneumatic pumps measured across all years upon which the emission factor is based (
                                <E T="03">i.e.</E>
                                , the cumulative value of “
                                <E T="8151">S</E>
                                <E T="03">y</E>
                                =1
                                <E T="53">n</E>
                                  
                                <E T="03">Count</E>
                                <E T="54">y</E>
                                ” term used in equation W-2A to § 98.233).
                            </P>
                            <P>
                                (C) Total number of natural gas driven pneumatic pumps that vent directly to the atmosphere and that were not directly measured according to the requirements in § 98.233(c)(1) or (c)(2)(iii) (
                                <E T="03">i.e.</E>
                                , “Count” in equation W-2B to § 98.233).
                            </P>
                            <P>
                                (D) The average estimated number of hours in the operating year the pumps were pumping liquid (
                                <E T="03">i.e.</E>
                                , “T” in equation W-2B to § 98.233).
                            </P>
                            <P>
                                (vi) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , cumulative for all natural gas driven pneumatic pumps for which emissions were directly measured and calculated as specified in § 98.233(c)(2)(ii) through (vi). Enter 0 if emissions from none of the natural gas driven pneumatic pumps at this well-pad or gathering and boosting site were measured during the reporting year.
                            </P>
                            <P>
                                (vii) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , cumulative for all natural gas driven pneumatic pumps for which emissions were directly measured and calculated as specified in § 98.233(c)(2)(ii) through (vi). Enter 0 if emissions from none of the natural gas driven pneumatic pumps at this well-pad or gathering and boosting site were measured during the reporting year.
                            </P>
                            <P>
                                (viii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , cumulative for all natural gas driven pneumatic pumps for which emissions were calculated according to § 98.233(c)(2)(vii)(B) through (D). Enter 0 if emissions from all natural gas driven pneumatic pumps at this well-pad or gathering and boosting site were measured during the reporting year.
                            </P>
                            <P>
                                (ix) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , cumulative for all natural gas driven pneumatic pumps for which emissions were calculated according to § 98.233(c)(2)(vii)(B) through (D). Enter 0 if emissions from all natural gas driven pneumatic pumps at this well-pad site or gathering and boosting site were measured during the reporting year.
                            </P>
                            <P>(5) If you used Calculation Method 3 according to § 98.233(c)(3) to calculate vented emissions, report the information in paragraphs (c)(5)(i) through (iv) of this section for the natural gas driven pneumatic pumps subject to Calculation Method 3.</P>
                            <P>
                                (i) Number of pumps that vent directly to the atmosphere (
                                <E T="03">i.e.</E>
                                , “Count” in equation W-2B to § 98.233).
                            </P>
                            <P>(ii) Average estimated number of hours in the calendar year that natural gas driven pneumatic pumps that vented directly to atmosphere were pumping liquid (“T” in equation W-2B to § 98.233).</P>
                            <P>
                                (iii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for all natural gas driven pneumatic pumps vented directly to the atmosphere combined, calculated according to § 98.233(c)(3).
                            </P>
                            <P>
                                (iv) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for all natural gas driven pneumatic pumps vented directly to the atmosphere combined, calculated according to § 98.233(c)(3).
                            </P>
                            <P>
                                (d) 
                                <E T="03">Acid gas removal units and nitrogen removal units.</E>
                                 You must indicate whether your facility has any acid gas removal units or nitrogen removal units that vent directly to the atmosphere, to a flare or engine, or to a sulfur recovery plant. For any acid gas removal units or nitrogen removal units that vent directly to the atmosphere or to a sulfur recovery plant, you must report the information specified in paragraphs (d)(1) and (2) of this section. If the acid gas removal units or nitrogen removal units that vent directly to the atmosphere for only part of the year, report the information specified in paragraph (d)(2) if this section for the part of the year that the units vent directly to the atmosphere. For acid gas removal units or nitrogen removal units that were routed to an engine or routed to a vapor recovery system for the entire year, you must only report the information specified in paragraphs (d)(1)(i) through (v) and (x) of this section. For acid gas removal units or nitrogen removal units that were routed to flares for which you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), you must report the information specified in paragraphs (d)(1)(i) through (v) and (x) of this section, as applicable. For acid gas removal units that were routed to flares for which you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(d) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (d)(1)(i) through (vii) and (x) of this section and paragraph (d)(2) of this section.
                            </P>
                            <P>(1) You must report the information specified in paragraphs (d)(1)(i) through (xi) of this section for each acid gas removal unit or nitrogen removal unit, as applicable.</P>
                            <P>(i) A unique name or ID number for the acid gas removal unit or nitrogen removal unit. For the onshore petroleum and natural gas production and the onshore petroleum and natural gas gathering and boosting industry segments, a different name or ID may be used for a single acid gas removal unit or nitrogen removal unit for each location it operates at in a given year.</P>
                            <P>(ii) Whether the acid gas removal unit or nitrogen removal unit vent was routed to a flare. If so, report the information specified in paragraphs (d)(1)(ii)(A) through (D) of this section for acid gas removal units and the information specified in paragraph (d)(1)(ii)(B) of this section for nitrogen removal units.</P>
                            <P>(A) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(d) as specified in § 98.233(n)(3)(ii)(B).</P>
                            <P>(B) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.</P>
                            <P>(C) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section to which the acid gas removal unit or nitrogen removal unit vent was routed.</P>
                            <P>(D) The unique ID for the stream routed to the flare as specified in paragraph (n)(3) of this section from the acid gas removal unit or nitrogen removal unit vent.</P>
                            <P>
                                (iii) Whether the acid gas removal unit or nitrogen removal unit vent was routed to combustion, and if so, whether 
                                <PRTPAGE P="42299"/>
                                it was routed for the entire year or only part of the year.
                            </P>
                            <P>(iv) Whether the acid gas removal unit or nitrogen removal unit vent was routed to a vapor recovery system, and if so, whether it was routed for the entire year or only part of the year.</P>
                            <P>(v) Total feed rate entering the acid gas removal unit or nitrogen removal unit, using a meter or engineering estimate based on process knowledge or best available data, in million standard cubic feet per year.</P>
                            <P>(vi) If the acid gas removal unit or nitrogen removal unit was routed to a flare, to combustion, or to vapor recovery for only part of the year, the feed rate entering the acid gas removal unit or nitrogen removal unit during the portion of the year that the emissions were vented directly to the atmosphere, using a meter or engineering estimate based on process knowledge or best available data, in million standard cubic feet per year.</P>
                            <P>
                                (vii) The calculation method used to calculate CO
                                <E T="52">2</E>
                                 and CH
                                <E T="52">4</E>
                                 emissions from the acid gas removal unit or to calculate CH
                                <E T="52">4</E>
                                 emissions from the nitrogen removal unit, as specified in § 98.233(d).
                            </P>
                            <P>
                                (viii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , vented directly to the atmosphere from the acid gas removal unit, calculated using any one of the calculation methods specified in § 98.233(d) and as specified in § 98.233(d)(11) and (12).
                            </P>
                            <P>
                                (ix) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , vented directly to the atmosphere from the acid gas removal unit or nitrogen removal unit, calculated using any one of the calculation methods specified in § 98.233(d) and as specified in § 98.233(d)(11) and (12).
                            </P>
                            <P>(x) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(2) You must report information specified in paragraphs (d)(2)(i) through (iii) of this section, applicable to the calculation method reported in paragraph (d)(1)(iii) of this section, for each acid gas removal unit or nitrogen removal unit.</P>
                            <P>
                                (i) If you used Calculation Method 1 or Calculation Method 2 as specified in § 98.233(d) to calculate CO
                                <E T="52">2</E>
                                 emissions from the acid gas removal unit and Calculation Method 2 as specified in § 98.233(d) to calculate CH
                                <E T="52">4</E>
                                 emissions from the acid gas removal unit or nitrogen removal unit, then you must report the information specified in paragraphs (d)(2)(i)(A) through (C) of this section, as applicable.
                            </P>
                            <P>
                                (A) Annual average volumetric fraction of CO
                                <E T="52">2</E>
                                 in the vent gas exiting the acid gas removal unit.
                            </P>
                            <P>
                                (B) Annual average volumetric fraction of CH
                                <E T="52">4</E>
                                 in the vent gas exiting the acid gas removal unit or nitrogen removal unit.
                            </P>
                            <P>(C) Annual volume of gas vented from the acid gas removal unit or nitrogen removal unit, in cubic feet.</P>
                            <P>(D) The temperature that corresponds to the reported annual volume of gas vented from the unit, in degrees Fahrenheit. If the annual volume of gas vented is reported in actual cubic feet, report the actual temperature; if it is reported in standard cubic feet, report 60 °F.</P>
                            <P>(E) The pressure that corresponds to the reported annual volume of gas vented from the unit, in pounds per square inch absolute. If the annual volume of gas vented is reported in actual cubic feet, report the actual pressure; if it is reported in standard cubic feet, report 14.7 psia.</P>
                            <P>
                                (ii) If you used Calculation Method 3 as specified in § 98.233(d) to calculate CO
                                <E T="52">2</E>
                                 or CH
                                <E T="52">4</E>
                                 emissions from the acid gas removal unit or nitrogen removal unit, then you must report the information specified in paragraphs (d)(2)(ii)(A) through (M) of this section, as applicable depending on the equation used.
                            </P>
                            <P>(A) Indicate which equation was used (equation W-4A, W-4B, or W-4C to § 98.233).</P>
                            <P>
                                (B) Annual average volumetric fraction of CO
                                <E T="52">2</E>
                                 in the natural gas flowing out of the acid gas removal unit, as specified in equation W-4A, equation W-4B, or equation W-4C to § 98.233.
                            </P>
                            <P>
                                (C) Annual average volumetric fraction of CO
                                <E T="52">2</E>
                                 content in natural gas flowing into the acid gas removal unit, as specified in equation W-4A, equation W-4B, or equation W-4C to § 98.233.
                            </P>
                            <P>
                                (D) Annual average volumetric fraction of CO
                                <E T="52">2</E>
                                 in the vent gas exiting the acid gas removal unit, as specified in equation W-4A or equation W-4B to § 98.233.
                            </P>
                            <P>
                                (E) Annual average volumetric fraction of CH
                                <E T="52">4</E>
                                 in the natural gas flowing out of the acid gas removal unit or nitrogen removal unit, as specified in equation W-4A, equation W-4B, or equation W-4C to § 98.233.
                            </P>
                            <P>
                                (F) Annual average volumetric fraction of CH
                                <E T="52">4</E>
                                 content in natural gas flowing into the acid gas removal unit or nitrogen removal unit, as specified in equation W-4A, equation W-4B, or equation W-4C to § 98.233.
                            </P>
                            <P>
                                (G) Annual average volumetric fraction of CH
                                <E T="52">4</E>
                                 in the vent gas exiting the acid gas removal unit or nitrogen removal unit, as specified in equation W-4A or equation W-4B to § 98.233.
                            </P>
                            <P>(H) The total annual volume of natural gas flow into the acid gas removal unit or nitrogen removal unit, as specified in equation W-4A or equation W-4C to § 98.233, in cubic feet at actual conditions.</P>
                            <P>(I) The temperature that corresponds to the reported total annual volume of natural gas flow into the acid gas removal unit or nitrogen removal unit, as specified in equation W-4A or equation W-4C to § 98.233, in degrees Fahrenheit. If the total annual volume of natural gas flow is reported in actual cubic feet, report the actual temperature; if it is reported in standard cubic feet, report 60 °F.</P>
                            <P>(J) The pressure that corresponds to the reported total annual volume of natural gas flow into the acid gas removal unit or nitrogen removal unit, as specified in equation W-4A or equation W-4C to § 98.233, in pounds per square inch absolute. If the total annual volume of natural gas flow is reported in actual cubic feet, report the actual pressure; if it is reported in standard cubic feet, report 14.7 psia.</P>
                            <P>(K) The total annual volume of natural gas flow out of the acid gas removal unit or nitrogen removal unit, as specified in equation W-4B or equation W-4C to § 98.233, in cubic feet at actual conditions.</P>
                            <P>(L) The temperature that corresponds to the reported total annual volume of natural gas flow out of the acid gas removal unit or nitrogen removal unit, as specified in equation W-4B or equation W-4C to § 98.233, in degrees Fahrenheit. If the total annual volume of natural gas flow is reported in actual cubic feet, report the actual temperature; if it is reported in standard cubic feet, report 60 °F.</P>
                            <P>(M) The pressure that corresponds to the reported total annual volume of natural gas flow out of the acid gas removal unit or nitrogen removal unit, as specified in equation W-4B or equation W-4C to § 98.233, in pounds per square inch absolute. If the total annual volume of natural gas flow is reported in actual cubic feet, report the actual pressure; if it is reported in standard cubic feet, report 14.7 psia.</P>
                            <P>
                                (iii) If you used Calculation Method 4 as specified in § 98.233(d) to calculate CO
                                <E T="52">2</E>
                                 or CH
                                <E T="52">4</E>
                                 emissions from the acid gas removal unit or nitrogen removal unit, then you must report the information specified in paragraphs (d)(2)(iii)(A) through (O) of this section, as applicable to the simulation software package used.
                            </P>
                            <P>
                                (A) The name of the simulation software package used.
                                <PRTPAGE P="42300"/>
                            </P>
                            <P>(B) Annual average natural gas feed temperature, in degrees Fahrenheit.</P>
                            <P>(C) Annual average natural gas feed pressure, in pounds per square inch.</P>
                            <P>(D) Annual average natural gas feed flow rate, in standard cubic feet per minute.</P>
                            <P>(E) Annual average acid gas content of the feed natural gas, in mole percent.</P>
                            <P>(F) Annual average acid gas content of the outlet natural gas, in mole percent.</P>
                            <P>(G) Annual average methane content of the feed natural gas, in mole percent.</P>
                            <P>(H) Annual average methane content of the outlet natural gas, in mole percent.</P>
                            <P>(I) Total annual unit operating hours, excluding downtime for maintenance or standby, in hours per year.</P>
                            <P>(J) Annual average exit temperature of the natural gas, in degrees Fahrenheit.</P>
                            <P>(K) Annual average solvent pressure, in pounds per square inch.</P>
                            <P>(L) Annual average solvent temperature, in degrees Fahrenheit.</P>
                            <P>(M) Annual average solvent circulation rate, in gallons per minute.</P>
                            <P>
                                (N) Solvent type used for the majority of the year, from one of the following options: Selexol
                                <E T="51">TM</E>
                                , Rectisol®, Purisol
                                <E T="51">TM</E>
                                , Fluor Solvent
                                <E T="51">SM</E>
                                , Benfield
                                <E T="51">TM</E>
                                , 20 wt% MEA, 30 wt% MEA, 40 wt% MDEA, 50 wt% MDEA, and other (specify).
                            </P>
                            <P>
                                (O) If a vent meter is installed and you elected to use Calculation Method 4 for an AGR, report the information in paragraphs (d)(2)(iii)(O)(
                                <E T="03">1</E>
                                ) through (
                                <E T="03">3</E>
                                ) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) The total annual volume of vent gas flowing out of the AGR in cubic feet per year at actual conditions as determined by flow meter (“V
                                <E T="52">a,meter</E>
                                ” from equation W-4D to § 98.233).
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) The total annual volume of vent gas flowing out of the AGR in cubic feet per year at actual conditions as determined the standard simulation software package (“V
                                <E T="52">a,sim</E>
                                ” from equation W-4D to § 98.233).
                            </P>
                            <P>
                                (
                                <E T="03">3</E>
                                ) If the calculated percent difference between the vent volumes (“PD” from equation W-4D to § 98.233) is greater than 20 percent, provide a brief description of the reason for the difference.
                            </P>
                            <P>
                                (e) 
                                <E T="03">Dehydrators.</E>
                                 You must indicate whether your facility contains any of the following equipment: Glycol dehydrators for which you calculated emissions using Calculation Method 1 according to § 98.233(e)(1), glycol dehydrators for which you calculated emissions using Calculation Method 2 according to § 98.233(e)(2), and dehydrators that use desiccant. If your facility contains any of the equipment listed in this paragraph (e), then you must report the applicable information in paragraphs (e)(1) through (3) of this section. For dehydrators that were routed to flares for which you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), you must report the information specified in paragraph (e)(4) of this section. For dehydrators that were routed to flares for which you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(e) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the applicable information in paragraphs (e)(1) through (3) of this section and the information specified in paragraph (e)(4) of this section.
                            </P>
                            <P>(1) For each glycol dehydrator for which you calculated emissions using Calculation Method 1 (as specified in § 98.233(e)(1)), you must report the information specified in paragraphs (e)(1)(i) through (xviii) of this section for the dehydrator. If reported emissions are based on more than one simulation, you must report the average of the simulation inputs.</P>
                            <P>(i) A unique name or ID number for the dehydrator. For the onshore petroleum and natural gas production and the onshore petroleum and natural gas gathering and boosting industry segments, a different name or ID may be used for a single dehydrator for each location it operates at in a given year.</P>
                            <P>(ii) Dehydrator feed natural gas flow rate, in million standard cubic feet per day.</P>
                            <P>(iii) Dehydrator feed natural gas water content, in pounds per million standard cubic feet.</P>
                            <P>(iv) Dehydrator outlet natural gas water content, in pounds per million standard cubic feet.</P>
                            <P>
                                (v) Dehydrator absorbent circulation pump type (
                                <E T="03">e.g.</E>
                                , natural gas pneumatic, air pneumatic, or electric).
                            </P>
                            <P>(vi) Dehydrator absorbent circulation rate, in gallons per minute.</P>
                            <P>
                                (vii) Type of absorbent (
                                <E T="03">e.g.</E>
                                , triethylene glycol (TEG), diethylene glycol (DEG), or ethylene glycol (EG)).
                            </P>
                            <P>(viii) Whether stripping gas is used in dehydrator.</P>
                            <P>(ix) Whether a flash tank separator is used in dehydrator.</P>
                            <P>(x) Total time the dehydrator is operating during the year, in hours.</P>
                            <P>(xi) Temperature of the wet natural gas at the absorber inlet, in degrees Fahrenheit.</P>
                            <P>(xii) Pressure of the wet natural gas at the absorber inlet, in pounds per square inch gauge.</P>
                            <P>
                                (xiii) Mole fraction of CH
                                <E T="52">4</E>
                                 in wet natural gas.
                            </P>
                            <P>
                                (xiv) Mole fraction of CO
                                <E T="52">2</E>
                                 in wet natural gas.
                            </P>
                            <P>(xv) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(xvi) If a flash tank separator is used in the dehydrator, then you must report the information specified in paragraphs (e)(1)(xvi)(A) through (F) of this section for the emissions from the flash tank vent, as applicable. If flash tank emissions were routed to a regenerator firebox/fire tubes, then you must also report the information specified in paragraphs (e)(1)(xvi)(G) through (I) of this section for the combusted emissions from the flash tank vent.</P>
                            <P>(A) Whether any flash gas emissions are vented directly to the atmosphere, routed to a flare, routed to the regenerator firebox/fire tubes, routed to a vapor recovery system, used as stripping gas, or any combination.</P>
                            <P>
                                (B) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , from the flash tank when not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1) and, if applicable, (e)(4).
                            </P>
                            <P>
                                (C) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , from the flash tank when not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1) and, if applicable, paragraph (e)(4) of this section.
                            </P>
                            <P>
                                (D) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , that resulted from routing flash gas to a regenerator firebox/fire tubes, calculated according to § 98.233(e)(5).
                            </P>
                            <P>
                                (E) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , that resulted from routing flash gas to a regenerator firebox/fire tubes, calculated according to § 98.233(e)(5).
                            </P>
                            <P>
                                (F) Annual N
                                <E T="52">2</E>
                                O emissions, in metric tons N
                                <E T="52">2</E>
                                O, that resulted from routing flash gas to a regenerator firebox/fire tubes, calculated according to § 98.233(e)(5).
                            </P>
                            <P>(G) Indicate whether the regenerator firebox/fire tubes was monitored with a CEMS. If a CEMS was used, then paragraphs (e)(1)(xvi)(E) and (F) and (e)(1)(xvi)(H) and (I) of this section do not apply.</P>
                            <P>(H) Total volume of gas from the flash tank to a regenerator firebox/fire tubes, in standard cubic feet.</P>
                            <P>(I) Average combustion efficiency, expressed as a fraction of gas from the flash tank combusted by a burning regenerator firebox/fire tubes.</P>
                            <P>
                                (xvii) Report the information specified in paragraphs (e)(1)(xvii)(A) through (F) 
                                <PRTPAGE P="42301"/>
                                of this section for the emissions from the still vent, as applicable. If still vent emissions were routed to a regenerator firebox/fire tubes, then you must also report the information specified in paragraphs (e)(1)(xvii)(G) through (I) of this section for the combusted emissions from the still vent.
                            </P>
                            <P>(A) Whether any still vent emissions are vented directly to the atmosphere, routed to a flare, routed to the regenerator firebox/fire tubes, routed to a vapor recovery system, used as stripping gas, or any combination.</P>
                            <P>
                                (B) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , from the still vent when not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1), and, if applicable, (e)(4).
                            </P>
                            <P>
                                (C) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , from the still vent when not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1) and, if applicable, (e)(4).
                            </P>
                            <P>
                                (D) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , that resulted from routing still vent gas to a regenerator firebox/fire tubes, calculated according to §  98.233(e)(5).
                            </P>
                            <P>
                                (E) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , that resulted from routing still vent gas to a regenerator firebox/fire tubes, calculated according to §  98.233(e)(5).
                            </P>
                            <P>
                                (F) Annual N
                                <E T="52">2</E>
                                O emissions, in metric tons N
                                <E T="52">2</E>
                                O, that resulted from routing still vent gas to a regenerator firebox/fire tubes, calculated according to §  98.233(e)(5).
                            </P>
                            <P>(G) Indicate whether the regenerator firebox/fire tubes were monitored with a CEMS. If a CEMS was used, then paragraphs (e)(1)(xvii)(E) and (F) and (e)(1)(xvii)(H) and (I) of this section do not apply.</P>
                            <P>(H) Total volume of gas from the still vent to a regenerator firebox/fire tubes, in standard cubic feet.</P>
                            <P>(I) Average combustion efficiency, expressed as a fraction of gas from the still vent combusted by a burning regenerator firebox/fire tubes.</P>
                            <P>(xviii) Name of the software package used.</P>
                            <P>(2) You must report the information specified in paragraphs (e)(2)(i) through (vi) of this section for all glycol dehydrators with an annual average daily natural gas throughput greater than 0 million standard cubic feet per day and less than 0.4 million standard cubic feet per day for which you calculated emissions using Calculation Method 2 (as specified in § 98.233(e)(2)) at the facility, well-pad site, or gathering and boosting site.</P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) The total number of dehydrators at the facility, well-pad site, or gathering and boosting site for which you calculated emissions using Calculation Method 2.</P>
                            <P>(iii) Whether any dehydrator emissions were routed to a vapor recovery system. If any dehydrator emissions were routed to a vapor recovery system, then you must report the total number of dehydrators at the facility that routed to a vapor recovery system.</P>
                            <P>
                                (iv) Whether any dehydrator emissions were routed to a control device that reduces CO
                                <E T="52">2</E>
                                 and/or CH
                                <E T="52">4</E>
                                 emissions other than a vapor recovery system or a flare or regenerator firebox/fire tubes. If any dehydrator emissions were routed to a control device that reduces CO
                                <E T="52">2</E>
                                 and/or CH
                                <E T="52">4</E>
                                 emissions other than a vapor recovery system or a flare or regenerator firebox/fire tubes, then you must specify the type of control device(s) and the total number of dehydrators at the facility that were routed to each type of control device.
                            </P>
                            <P>(v) Whether any dehydrator emissions were routed to a flare or regenerator firebox/fire tubes. If any dehydrator emissions were routed to a flare or regenerator firebox/fire tubes, then you must report the information specified in paragraphs (e)(2)(v)(A) through (E) of this section.</P>
                            <P>(A) The total number of dehydrators routed to a flare and the total number of dehydrators routed to regenerator firebox/fire tubes.</P>
                            <P>(B) Total volume of gas from the flash tank to a regenerator firebox/fire tubes, in standard cubic feet.</P>
                            <P>
                                (C) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for the dehydrators routed to a regenerator firebox/fire tubes reported in paragraph (e)(2)(v)(A) of this section, calculated according to § 98.233(e)(5).
                            </P>
                            <P>
                                (D) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for the dehydrators routed to a regenerator firebox/fire tubes reported in paragraph (e)(2)(v)(A) of this section, calculated according to § 98.233(e)(5).
                            </P>
                            <P>
                                (E) Annual N
                                <E T="52">2</E>
                                O emissions, in metric tons N
                                <E T="52">2</E>
                                O, for the dehydrators routed to a regenerator firebox/fire tubes reported in paragraph (e)(2)(v)(A) of this section, calculated according to § 98.233(e)(5).
                            </P>
                            <P>(vi) For dehydrator emissions that were not routed to a flare or regenerator firebox/fire tubes, report the information specified in paragraphs (e)(2)(vi)(A) and (B) of this section.</P>
                            <P>
                                (A) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for emissions from all dehydrators reported in paragraph (e)(2)(ii) of this section that were not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(2) and, if applicable, (e)(4), where emissions are added together for all such dehydrators.
                            </P>
                            <P>
                                (B) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for emissions from all dehydrators reported in paragraph (e)(2)(ii) of this section that were not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(2) and, if applicable, (e)(4), where emissions are added together for all such dehydrators.
                            </P>
                            <P>(3) For dehydrators that use desiccant (as specified in § 98.233(e)(3)), you must report the information specified in paragraphs (e)(3)(i) through (viii) of this section for each well-pad site, gathering and boosting site, or facility, as applicable.</P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) Count of desiccant dehydrators as specified in paragraphs (e)(3)(ii)(A) and (B) of this section that had one or more openings during the calendar year at the facility, well-pad site, or gathering and boosting site for which you calculated emissions using Calculation Method 3.</P>
                            <P>
                                (A) The number of opened desiccant dehydrators that used deliquescing desiccant (
                                <E T="03">e.g.</E>
                                , calcium chloride or lithium chloride).
                            </P>
                            <P>
                                (B) The number of opened desiccant dehydrators that used regenerative desiccant (
                                <E T="03">e.g.</E>
                                , molecular sieves, activated alumina, or silica gel).
                            </P>
                            <P>(iii) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section, total physical volume of all opened dehydrator vessels.</P>
                            <P>(iv) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section, total number of dehydrator openings in the calendar year.</P>
                            <P>(v) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section, whether any dehydrator emissions were routed to a vapor recovery system. If any dehydrator emissions were routed to a vapor recovery system, then you must report the total number of dehydrators at the facility that routed to a vapor recovery system.</P>
                            <P>
                                (vi) For desiccant dehydrators at the facility, well-pad, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section, whether any 
                                <PRTPAGE P="42302"/>
                                dehydrator emissions were routed to a control device that reduces CO
                                <E T="52">2</E>
                                 and/or CH
                                <E T="52">4</E>
                                 emissions other than a vapor recovery system or a flare or a non-flare combustion unit. If any dehydrator emissions were routed to a control device that reduces CO
                                <E T="52">2</E>
                                 and/or CH
                                <E T="52">4</E>
                                 emissions other than a vapor recovery system or a flare or a non-flare combustion unit, then you must specify the type of control device(s) and the total number of dehydrators at the facility that were routed to each type of control device.
                            </P>
                            <P>(vii) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section, whether any dehydrator emissions were routed to a flare or a non-flare combustion unit. If any dehydrator emissions were routed to a flare or a non-flare combustion unit, then you must report the information specified in paragraphs (e)(3)(vii)(A) through (E) of this section.</P>
                            <P>(A) The total number of dehydrators routed to a flare and the total number of dehydrators routed to a non-flare combustion unit.</P>
                            <P>(B) Total volume of gas from the flash tank to non-flare combustion units, in standard cubic feet.</P>
                            <P>
                                (C) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for the dehydrators routed to non-flare combustion units reported in paragraph (e)(3)(vii)(A) of this section, calculated according to § 98.233(e)(5).
                            </P>
                            <P>
                                (D) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for the dehydrators routed to non-flare combustion units reported in paragraph (e)(3)(vii)(A) of this section, calculated according to § 98.233(e)(5).
                            </P>
                            <P>
                                (E) Annual N
                                <E T="52">2</E>
                                O emissions, in metric tons N
                                <E T="52">2</E>
                                O, for the dehydrators routed to non-flare combustion units reported in paragraph (e)(3)(vii)(A) of this section, calculated according to § 98.233(e)(5).
                            </P>
                            <P>(viii) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section that were not routed to a flare or a non-flare combustion unit, report the information specified in paragraphs (e)(3)(viii)(A) and (B) of this section.</P>
                            <P>
                                (A) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for emissions from all desiccant dehydrators reported under paragraph (e)(3)(ii) of this section that are not venting to a flare or non-flare combustion units, calculated according to § 98.233(e)(3) and, if applicable, (e)(4), and summing for all such dehydrators.
                            </P>
                            <P>
                                (B) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for emissions from all desiccant dehydrators reported in paragraph (e)(3)(ii) of this section that are not venting to a flare or non-flare combustion unit, calculated according to § 98.233(e)(3), and, if applicable, (e)(4), and summing for all such dehydrators.
                            </P>
                            <P>(4) For dehydrators that were routed to flares, report the information specified in paragraphs (e)(4)(i) through (iv) of this section.</P>
                            <P>(i) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(e) as specified in § 98.233(n)(3)(ii)(B).</P>
                            <P>(ii) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.</P>
                            <P>(iii) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section to which the dehydrator vent was routed.</P>
                            <P>(iv) The unique ID for the stream routed to the flare as specified in paragraph (n)(3) of this section from the dehydrator.</P>
                            <P>
                                (f) 
                                <E T="03">Liquids unloading.</E>
                                 You must indicate whether well venting for liquids unloading occurs at your facility, and if so, which methods (as specified in § 98.233(f)) were used to calculate emissions. If your facility performs well venting for liquids unloading venting to the atmosphere and uses Calculation Method 1, then you must report the information specified in paragraph (f)(1) of this section. If the facility performs liquids unloading venting to the atmosphere and uses Calculation Method 2 or 3, then you must report the information specified in paragraph (f)(2) of this section.
                            </P>
                            <P>(1) For each well for which you used Calculation Method 1 to calculate natural gas emissions from well venting for liquids unloading vented to the atmosphere, report the information specified in paragraphs (f)(1)(i) through (xii) of this section. Report information separately for wells with plunger lifts and wells without plunger lifts by unloading type combination (with or without plunger lifts, automated or manual unloading).</P>
                            <P>(i) Well ID number.</P>
                            <P>(ii) Well tubing diameter and pressure group ID.</P>
                            <P>(iii) Unloading type combination (with or without plunger lifts, automated or manual unloading).</P>
                            <P>(iv) [Reserved]</P>
                            <P>(v) Indicate whether the monitoring period used to determine the cumulative amount of time venting to the atmosphere was not the full calendar year.</P>
                            <P>
                                (vi) Cumulative amount of time the well was vented directly to the atmosphere (“T
                                <E T="52">p</E>
                                ” from equation W-7A or W-7B to § 98.233), in hours.
                            </P>
                            <P>(vii) Cumulative number of unloadings vented directly to the atmosphere for the well.</P>
                            <P>(viii) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, calculated according to § 98.233(f)(1).</P>
                            <P>
                                (ix) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , from well venting for liquids unloading, calculated according to § 98.233(f)(1) and (4).
                            </P>
                            <P>
                                (x) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , from well venting for liquids unloading, calculated according to § 98.233(f)(1) and (4).
                            </P>
                            <P>(xi) For each well tubing diameter group and pressure group combination, you must report the information specified in paragraphs (f)(1)(xi)(A) through (F) of this section for each individual well not using a plunger lift that was tested during the year.</P>
                            <P>(A) Well ID number of tested well.</P>
                            <P>(B) Casing pressure, in pounds per square inch absolute.</P>
                            <P>(C) Internal casing diameter, in inches.</P>
                            <P>(D) Measured depth of the well, in feet.</P>
                            <P>(E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic feet per hour.</P>
                            <P>(F) Unloading type (automated or manual).</P>
                            <P>(xii) For each well tubing diameter group and pressure group combination, you must report the information specified in paragraphs (f)(1)(xii)(A) through (F) of this section for each individual well using a plunger lift that was tested during the year.</P>
                            <P>(A) Well ID number.</P>
                            <P>(B) The tubing pressure, in pounds per square inch absolute.</P>
                            <P>(C) The internal tubing diameter, in inches.</P>
                            <P>(D) Measured depth of the well, in feet.</P>
                            <P>(E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic feet per hour.</P>
                            <P>(F) Unloading type (automated or manual).</P>
                            <P>
                                (2) For each well for which you used Calculation Method 2 or 3 (as specified in § 93.233(f)) to calculate natural gas emissions from well venting for liquids unloading vented to the atmosphere, you must report the information in paragraphs (f)(2)(i) through (xii) of this section. Report information separately 
                                <PRTPAGE P="42303"/>
                                for each calculation method and unloading type combination (with or without plunger lifts, automated or manual unloadings).
                            </P>
                            <P>(i) Well ID number.</P>
                            <P>(ii) Calculation method.</P>
                            <P>(iii) Unloading type combination (with or without plunger lifts, automated or manual unloadings).</P>
                            <P>(iv) [Reserved]</P>
                            <P>(v) Cumulative number of unloadings venting directly to the atmosphere for the well.</P>
                            <P>(vi) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, calculated according to § 98.233(f)(2) or (3), as applicable.</P>
                            <P>
                                (vii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , from well venting for liquids unloading, calculated according to § 98.233(f)(2) or (3), as applicable, and § 98.233(f)(4).
                            </P>
                            <P>
                                (viii) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , from well venting for liquids unloading, calculated according to § 98.233(f)(2) or (3), as applicable, and § 98.233(f)(4).
                            </P>
                            <P>
                                (ix) Average flow-line rate of gas (average of “SFR
                                <E T="52">p</E>
                                ” from equation W-8 or W-9 to § 98.233, as applicable), at standard conditions in cubic feet per hour.
                            </P>
                            <P>
                                (x) Cumulative amount of time that wells were left open to the atmosphere during unloading events (sum of “HR
                                <E T="52">p,q</E>
                                ” from equation W-8 or W-9 to § 98.233, as applicable), in hours.
                            </P>
                            <P>(xi) For each well without plunger lifts, the information in paragraphs (f)(2)(xi)(A) through (C) of this section.</P>
                            <P>
                                (A) Internal casing diameter (“CD
                                <E T="52">p</E>
                                ” from equation W-8 to § 98.233), in inches.
                            </P>
                            <P>
                                (B) Well depth (“WD
                                <E T="52">p</E>
                                ” from equation W-8 to § 98.233), in feet.
                            </P>
                            <P>
                                (C) Shut-in pressure, surface pressure, or casing pressure (“SP
                                <E T="52">p</E>
                                ” from equation W-8 to § 98.233), in pounds per square inch absolute.
                            </P>
                            <P>(xii) For each well with plunger lifts, the information in paragraphs (f)(2)(xiii)(A) through (C) of this section.</P>
                            <P>
                                (A) Internal tubing diameter (“TD
                                <E T="52">p</E>
                                ” from equation W-9 to § 98.233), in inches.
                            </P>
                            <P>
                                (B) Tubing depth (“WD
                                <E T="52">p</E>
                                ” from equation W-9 to § 98.233), in feet.
                            </P>
                            <P>
                                (C) Flow line pressure (“SP
                                <E T="52">p</E>
                                ” from equation W-9 to § 98.233), in pounds per square inch absolute.
                            </P>
                            <P>
                                (g) 
                                <E T="03">Completions and workovers with hydraulic fracturing.</E>
                                 You must indicate whether your facility had any well completions or workovers with hydraulic fracturing during the calendar year. If your facility had well completions or workovers with hydraulic fracturing during the calendar year that vented directly to the atmosphere, then you must report information specified in paragraphs (g)(1) through (10) of this section, for each well. If your facility had well completions or workovers with hydraulic fracturing during the year that routed to flares and you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (g)(1) through (3) and (10) of this section, for each well. If your facility had well completions or workovers with hydraulic fracturing during the year that routed to flares and you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(g) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (g)(1) through (6) and (10) of this section, for each well. Report information separately for completions and workovers.
                            </P>
                            <P>(1) Well ID number.</P>
                            <P>(2) Well type combination (horizontal or vertical, flared or vented, reduced emission completion or not a reduced emission completion, gas well or oil well).</P>
                            <P>(3) Number of completions or workovers for each well.</P>
                            <P>(4) Calculation method used.</P>
                            <P>(5) If you used equation W-10A to § 98.233 to calculate annual volumetric total gas emissions, then you must report the information specified in paragraphs (g)(5)(i) through (v) of this section.</P>
                            <P>
                                (i) Cumulative gas flowback time, in hours, for all completions or workovers at the well from when gas is first detected until sufficient quantities are present to enable separation, and the cumulative flowback time, in hours, after sufficient quantities of gas are present to enable separation (sum of “T
                                <E T="52">p,i</E>
                                ” and sum of “T
                                <E T="52">p,s</E>
                                ” values used in equation W-10A to § 98.233). You may delay the reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the total number of hours of flowback from the well during completions or workovers.
                            </P>
                            <P>
                                (ii) If the well is a measured well for the sub-basin and well-type combination, the flowback rate, in standard cubic feet per hour (average of “FR
                                <E T="52">s,p</E>
                                ” values used in equation W-12A to § 98.233). You may delay the reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured flowback rate(s) during well completion or workover for the well.
                            </P>
                            <P>(iii) If you used equation W-12C to § 98.233 to calculate the average gas production rate for an oil well, then you must report the information specified in paragraphs (g)(5)(iii)(A) and (B) of this section.</P>
                            <P>
                                (A) Gas to oil ratio for the well in standard cubic feet of gas per barrel of oil (“GOR
                                <E T="52">p</E>
                                ” in equation W-12C to § 98.233). You may delay the reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the gas to oil ratio for the well.
                            </P>
                            <P>
                                (B) Volume of oil produced during the first 30 days of production after completion of the newly drilled well or well workover using hydraulic fracturing, in barrels (“V
                                <E T="52">p</E>
                                ” in equation W-12C to § 98.233). You may delay the reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the volume of oil produced during the first 30 days of production after well completion or workover for the well.
                            </P>
                            <P>(iv) Whether the flow rate during the initial flowback period was determined using:</P>
                            <P>(A) A recording flow meter (digital or analog) installed on the vent line, downstream of a separator.</P>
                            <P>(B) A multiphase flow meter upstream of the separator.</P>
                            <P>(C) Equation W-11A or W-11B to § 98.233.</P>
                            <P>(v) Whether the flow rate when sufficient quantities are present to enable separation was determined using:</P>
                            <P>(A) A recording flow meter (digital or analog) installed on the vent line, downstream of a separator.</P>
                            <P>(B) Equation W-11A or W-11B to § 98.233.</P>
                            <P>
                                (6) If you used equation W-10B to § 98.233 to calculate annual volumetric total gas emissions, then you must report the information specified in paragraphs (g)(6)(i) through (iii) of this section.
                                <PRTPAGE P="42304"/>
                            </P>
                            <P>
                                (i) Vented natural gas volume, in standard cubic feet (“FV
                                <E T="52">s,p</E>
                                ” in equation W-10B to § 98.233).
                            </P>
                            <P>
                                (ii) Flow rate at the beginning of the period of time when sufficient quantities of gas are present to enable separation, in standard cubic feet per hour (“FR
                                <E T="52">p,i</E>
                                ” in equation W-10B to § 98.233).
                            </P>
                            <P>(iii) If a multiphase flowmeter was used to measure the flow rate during the initial flowback period, report the average flow rate measured by the multiphase flow meter from the initiation of flowback to the beginning of the period of time when sufficient quantities of gas present to enable separation in standard cubic feet per hour.</P>
                            <P>
                                (7) Annual gas emissions, in standard cubic feet (“E
                                <E T="52">s,n</E>
                                ” in equation W-10A or W-10B to § 98.233).
                            </P>
                            <P>
                                (8) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                .
                            </P>
                            <P>
                                (9) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                .
                            </P>
                            <P>(10) Indicate whether natural gas emissions from completion(s) or workover(s) with hydraulic fracturing were routed to a flare and emissions are reported according to paragraph (n) of this section, and if so, provide the information specified in paragraphs (g)(10)(i) through (iv) of this section.</P>
                            <P>(i) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(g) as specified in § 98.233(n)(3)(ii)(B).</P>
                            <P>(ii) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.</P>
                            <P>(iii) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section.</P>
                            <P>(iv) The unique ID for each stream routed to the flare as specified in paragraph (n)(3) of this section.</P>
                            <P>
                                (h) 
                                <E T="03">Completions and workovers without hydraulic fracturing.</E>
                                 You must indicate whether the facility had any gas well completions without hydraulic fracturing or any gas well workovers without hydraulic fracturing, and if the activities occurred with or without flaring. If the facility had gas well completions or workovers without hydraulic fracturing, then you must report the information specified in paragraphs (h)(1) through (4) of this section, as applicable.
                            </P>
                            <P>(1) For each well with one or more gas well completions without hydraulic fracturing and without flaring, report the information specified in paragraphs (h)(1)(i) through (vi) of this section.</P>
                            <P>(i) Well ID number.</P>
                            <P>(ii) Number of well completions that vented gas directly to the atmosphere without flaring.</P>
                            <P>
                                (iii) Total number of hours that gas vented directly to the atmosphere during venting for all completions without hydraulic fracturing (“T
                                <E T="52">p</E>
                                ” for completions that vented directly to the atmosphere as used in equation W-13B to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the total number of hours that gas vented directly to the atmosphere during completions for the well.
                            </P>
                            <P>
                                (iv) Average daily gas production rate for all completions without hydraulic fracturing without flaring, in standard cubic feet per hour (“V
                                <E T="52">p</E>
                                ” in equation W-13B to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured average daily gas production rate during completions for the well.
                            </P>
                            <P>
                                (v) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , that resulted from completions venting gas directly to the atmosphere (“E
                                <E T="52">s,p</E>
                                ” from equation W-13B to § 98.233 for completions that vented directly to the atmosphere, converted to mass emissions according to § 98.233(h)(1)).
                            </P>
                            <P>
                                (vi) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , that resulted from completions venting gas directly to the atmosphere (“E
                                <E T="52">s,p</E>
                                ” from equation W-13B to § 98.233 for completions that vented directly to the atmosphere, converted to mass emissions according to § 98.233(h)(1)).
                            </P>
                            <P>(2) If your facility had well completions without hydraulic fracturing and with flaring during the year and you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (h)(2)(i) through (ii) and (viii) of this section, for each well. If your facility had well completions without hydraulic fracturing during the year that routed to flares and you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(h) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (h)(2)(i) through (iv) and (viii) of this section, for each well.</P>
                            <P>(i) Well ID number.</P>
                            <P>(ii) Number of well completions that flared gas.</P>
                            <P>
                                (iii) Total number of hours that gas routed to a flare during venting for all completions without hydraulic fracturing (“T
                                <E T="52">p</E>
                                ” for completions that vented to a flare from equation W-13B to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the total number of hours that gas vented to the flare during completions for the well.
                            </P>
                            <P>
                                (iv) Average daily gas production rate for all completions without hydraulic fracturing with flaring, in standard cubic feet per hour (“V
                                <E T="52">p</E>
                                ” from equation W-13B to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured average daily gas production rate during completions for the well.
                            </P>
                            <P>(v) [Reserved]</P>
                            <P>(vi) [Reserved]</P>
                            <P>(vii) [Reserved]</P>
                            <P>(viii) Report the information specified in paragraphs (h)(2)(viii)(A) through (D).</P>
                            <P>(A) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(h) as specified in § 98.233(n)(3)(ii)(B).</P>
                            <P>(B) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.</P>
                            <P>(C) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section.</P>
                            <P>(D) The unique ID for each stream routed to the flare as specified in paragraph (n)(3) of this section.</P>
                            <P>
                                (3) For each well with one or more gas well workovers without hydraulic fracturing and without flaring, report the information specified in paragraphs (h)(3)(i) through (iv) of this section.
                                <PRTPAGE P="42305"/>
                            </P>
                            <P>(i) Well ID number.</P>
                            <P>(ii) Number of workovers that vented gas to the atmosphere without flaring.</P>
                            <P>
                                (iii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                 per year, that resulted from workovers venting gas directly to the atmosphere (“E
                                <E T="52">s,wo</E>
                                ” in equation W-13A to § 98.233 for workovers that vented directly to the atmosphere, converted to mass emissions as specified in § 98.233(h)(1)).
                            </P>
                            <P>
                                (iv) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                 per year, that resulted from workovers venting gas directly to the atmosphere (“E
                                <E T="52">s,wo</E>
                                ” in equation W-13A to § 98.233 for workovers that vented directly to the atmosphere, converted to mass emissions as specified in § 98.233(h)(1)).
                            </P>
                            <P>(4) If your facility had well workovers without hydraulic fracturing and with flaring during the year and you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (h)(4)(i) through (ii) and (vi) of this section, for each well. If your facility had well workovers without hydraulic fracturing during the year that routed to flares and you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(h) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (h)(4)(i) through (ii) and (vi) of this section, for each well.</P>
                            <P>(i) Well ID number.</P>
                            <P>(ii) Number of workovers that flared gas.</P>
                            <P>(iii) [Reserved]</P>
                            <P>(iv) [Reserved]</P>
                            <P>(v) [Reserved]</P>
                            <P>(vi) Report the information specified in paragraphs (h)(4)(vi)(A) through (D).</P>
                            <P>(A) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(h) as specified in § 98.233(n)(3)(ii)(B).</P>
                            <P>(B) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.</P>
                            <P>(C) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section.</P>
                            <P>(D) The unique ID for each stream routed to the flare as specified in paragraph (n)(3) of this section.</P>
                            <P>
                                (i) 
                                <E T="03">Blowdown vent stacks.</E>
                                 You must indicate whether your facility has blowdown vent stacks. If your facility has blowdown vent stacks, then you must report whether emissions were calculated by equipment or event type or by using flow meters or a combination of both. If you calculated emissions by equipment or event type for any blowdown vent stacks, then you must report the information specified in paragraph (i)(1) of this section considering, in aggregate, all blowdown vent stacks for which emissions were calculated by equipment or event type. If you calculated emissions using flow meters for any blowdown vent stacks, then you must report the information specified in paragraph (i)(2) of this section considering, in aggregate, all blowdown vent stacks for which emissions were calculated using flow meters. For the onshore natural gas transmission pipeline segment, you must also report the information in paragraph (i)(3) of this section. You must report the information specified in paragraphs (i)(1) through (3) of this section, as applicable, for each well-pad site (for onshore production), each gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments).
                            </P>
                            <P>
                                (1) 
                                <E T="03">Report by equipment or event type.</E>
                                 If you calculated emissions from blowdown vent stacks by the seven categories listed in § 98.233(i)(2)(iv)(A) for onshore petroleum and natural gas production, onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, LNG import and export equipment, or onshore petroleum and natural gas gathering and boosting industry segments, then you must report the information specified in paragraphs (i)(1)(i) through (v) of this section, as applicable. If a blowdown event resulted in emissions from multiple equipment or event types, and the emissions cannot be apportioned to the different equipment or event types, then you may report the information in paragraphs (i)(1)(ii) through (v) of this section for the equipment or event type that represented the largest portion of the emissions for the blowdown event. For the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments, if a blowdown event is not directly associated with a specific well-pad site or gathering and boosting site (
                                <E T="03">e.g.</E>
                                , a mid-field pipeline blowdown) or could be associated with multiple well-pad or gathering and boosting sites, then you may report the information in paragraphs (i)(1)(i) through (v) of this section for either the nearest well-pad site or gathering and boosting site upstream from the blowdown event or the well-pad site or gathering and boosting site that represented the largest portion of the emissions for the blowdown event, as appropriate. If you calculated emissions from blowdown vent stacks by the eight categories listed in § 98.233(i)(2)(iv)(B) for the natural gas distribution or onshore natural gas transmission pipeline industry segments, then you must report the information specified in paragraphs (i)(1)(ii) through (v) of this section, as applicable. If a blowdown event resulted in emissions from multiple equipment or event types, and the emissions cannot be apportioned to the different equipment or event types, then you may report the information in paragraphs (i)(1)(ii) through (v) of this section for the equipment or event type that represented the largest portion of the emissions for the blowdown event.
                            </P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) Equipment or event type. For the onshore petroleum and natural gas production, onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, LNG import and export equipment, or onshore petroleum and natural gas gathering and boosting industry segments, use the seven categories listed in § 98.233(i)(2)(iv)(A). For the natural gas distribution or onshore natural gas transmission pipeline industry segments, use the eight categories listed in § 98.233(i)(2)(iv)(B).</P>
                            <P>(iii) Total number of blowdowns in the calendar year for the equipment or event type (the sum of equation variable “N” from equation W-14A or equation W-14B to § 98.233, for all unique physical volumes for the equipment or event type).</P>
                            <P>
                                (iv) Annual CO
                                <E T="52">2</E>
                                 emissions for the equipment or event type, in metric tons CO
                                <E T="52">2</E>
                                , calculated according to § 98.233(i)(2)(iii).
                            </P>
                            <P>
                                (v) Annual CH
                                <E T="52">4</E>
                                 emissions for the equipment or event type, in metric tons CH
                                <E T="52">4</E>
                                , calculated according to § 98.233(i)(2)(iii).
                            </P>
                            <P>
                                (2) 
                                <E T="03">Report by flow meter.</E>
                                 If you elect to calculate emissions from blowdown vent stacks by using a flow meter according to § 98.233(i)(3), then you 
                                <PRTPAGE P="42306"/>
                                must report the information specified in paragraphs (i)(2)(i) through (iii) of this section, as applicable. For the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments, if a blowdown event is not directly associated with a specific well-pad site or gathering and boosting site (
                                <E T="03">e.g.</E>
                                , a mid-field pipeline blowdown) or could be associated with multiple well-pad sites or gathering and boosting sites, then you may report the information in paragraphs (i)(2)(i) through (iii) of this section for either the nearest well-pad site or gathering and boosting site upstream from the blowdown event or the well-pad site or gathering and boosting site that represented the largest portion of the emissions for the blowdown event, as appropriate.
                            </P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>
                                (ii) Annual CO
                                <E T="52">2</E>
                                 emissions from all blowdown vent stacks at the facility, well-pad site, or gathering and boosting site for which emissions were calculated using flow meters, in metric tons CO
                                <E T="52">2</E>
                                 (the sum of all CO
                                <E T="52">2</E>
                                 mass emission values calculated according to § 98.233(i)(3), for all flow meters).
                            </P>
                            <P>
                                (iii) Annual CH
                                <E T="52">4</E>
                                 emissions from all blowdown vent stacks at the facility, well-pad site, or gathering and boosting site for which emissions were calculated using flow meters, in metric tons CH
                                <E T="52">4</E>
                                , (the sum of all CH
                                <E T="52">4</E>
                                 mass emission values calculated according to § 98.233(i)(3), for all flow meters).
                            </P>
                            <P>
                                (3) 
                                <E T="03">Onshore natural gas transmission pipeline segment.</E>
                                 Report the information in paragraphs (i)(3)(i) through (iii) of this section for each state.
                            </P>
                            <P>
                                (i) Annual CO
                                <E T="52">2</E>
                                 emissions in metric tons CO
                                <E T="52">2</E>
                                .
                            </P>
                            <P>
                                (ii) Annual CH
                                <E T="52">4</E>
                                 emissions in metric tons CH
                                <E T="52">4</E>
                                .
                            </P>
                            <P>(iii) Annual number of blowdown events.</P>
                            <P>
                                (j) 
                                <E T="03">Hydrocarbon liquids and produced water storage tanks.</E>
                                 You must indicate whether your facility sends hydrocarbon produced liquids and/or produced water to atmospheric pressure storage tanks. If your facility sends hydrocarbon produced liquids and/or produced water to atmospheric pressure storage tanks, then you must indicate which Calculation Method(s) you used to calculate GHG emissions, and you must report the information specified in paragraphs (j)(1) and (2) of this section, as applicable. If you used Calculation Method 1 or Calculation Method 2 of § 98.233(j), and any atmospheric pressure storage tanks were observed to have malfunctioning dump valves during the calendar year, then you must indicate that dump valves were malfunctioning and must report the information specified in paragraph (j)(3) of this section. For hydrocarbon liquids and produced water storage tanks that were routed to flares for which you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), you must report the information specified in paragraph (j)(4) of this section. For hydrocarbon liquids and produced water storage tanks that were routed to flares for which you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(j) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the applicable information in paragraphs (j)(1) through (3) of this section and the information specified in paragraph (j)(4) of this section.
                            </P>
                            <P>(1) If you used Calculation Method 1 or Calculation Method 2 of § 98.233(j) to calculate GHG emissions, then you must report the information specified in paragraphs (j)(1)(i) through (xvi) of this section for each well-pad site (for onshore petroleum and natural gas production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments) and by calculation method and liquid type, as applicable. Onshore petroleum and natural gas gathering and boosting and onshore natural gas processing facilities do not report the information specified in paragraph (j)(1)(ix) of this section.</P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) Calculation method used, and name of the software package used if using Calculation Method 1.</P>
                            <P>(iii) The total annual hydrocarbon liquids or produced water volume from gas-liquid separators and direct from wells or non-separator equipment that is sent to applicable atmospheric pressure storage tanks, in barrels. You may delay reporting of this data element for onshore production if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells at the well-pad site with hydrocarbon liquids or produced water production flowing to gas-liquid separators or direct to atmospheric pressure storage tanks for which you used the same calculation method. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the total volume of hydrocarbon liquids or produced water from all wells and the well ID number(s) for the well(s) included in this volume.</P>
                            <P>(iv) The average well, gas-liquid separator, or non-separator equipment temperature, in degrees Fahrenheit.</P>
                            <P>(v) The average well, gas-liquid separator, or non-separator equipment pressure, in pounds per square inch gauge.</P>
                            <P>(vi) For atmospheric pressure storage tanks receiving hydrocarbon liquids, the average sales oil or stabilized hydrocarbon liquids API gravity, in degrees.</P>
                            <P>
                                (vii) If you used Calculation Method 1 of § 98.233(j) to calculate GHG emissions for atmospheric pressure storage tanks receiving hydrocarbon liquids, the flow-weighted average concentration (mole fraction) of CO
                                <E T="52">2</E>
                                 in flash gas from atmospheric pressure storage tanks (calculated as the sum of all products of the concentration of CO
                                <E T="52">2</E>
                                 in the flash gas for each storage tank times the total quantity of flash gas for that storage tank, divided by the sum of all flash gas emissions from storage tanks).
                            </P>
                            <P>
                                (viii) If you used Calculation Method 1 of § 98.233(j) to calculate GHG emissions for atmospheric pressure storage tanks receiving hydrocarbon liquids, the flow-weighted average concentration (mole fraction) of CH
                                <E T="52">4</E>
                                 in flash gas from atmospheric pressure storage tanks (calculated as the sum of all products of the concentration of CH
                                <E T="52">4</E>
                                 in the flash gas for each storage tank times the total quantity of flash gas for that storage tank, divided by the sum of all flash gas emissions from storage tanks).
                            </P>
                            <P>(ix) The number of wells sending hydrocarbon liquids or produced water to gas-liquid separators or directly to atmospheric pressure storage tanks.</P>
                            <P>(x) Count of atmospheric pressure storage tanks specified in paragraphs (j)(1)(x)(A) through (F) of this section.</P>
                            <P>(A) The number of fixed roof atmospheric pressure storage tanks.</P>
                            <P>(B) The number of floating roof atmospheric pressure storage tanks.</P>
                            <P>
                                (C) The number of atmospheric pressure storage tanks that vented gas directly to the atmosphere and did not control emissions using a vapor recovery system or one or more flares at any point during the reporting year.
                                <PRTPAGE P="42307"/>
                            </P>
                            <P>(D) The number of atmospheric pressure storage tanks that routed emissions to a vapor recovery system at any point during the reporting year.</P>
                            <P>(E) The number of atmospheric pressure storage tanks that routed emissions to one or more flares at any point during the reporting year.</P>
                            <P>(F) The number of atmospheric pressure storage tanks in paragraph (j)(1)(x)(D) or (E) of this section that had an open or not properly seated thief hatch at some point during the year while the storage tank was also routing emissions to a vapor recovery system and/or a flare.</P>
                            <P>
                                (xi) For atmospheric pressure storage tanks receiving hydrocarbon liquids, annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , that resulted from venting gas directly to the atmosphere, calculated according to § 98.233(j)(1) and (2).
                            </P>
                            <P>
                                (xii) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , that resulted from venting gas directly to the atmosphere, calculated according to § 98.233(j)(1) and (2).
                            </P>
                            <P>
                                (xiii) For the atmospheric pressure storage tanks receiving hydrocarbon liquids identified in paragraphs (j)(1)(x)(D) of this section, total CO
                                <E T="52">2</E>
                                 mass, in metric tons CO
                                <E T="52">2</E>
                                , that was recovered during the calendar year using a vapor recovery system.
                            </P>
                            <P>
                                (xiv) For the atmospheric pressure storage tanks identified in paragraphs (j)(1)(x)(D) of this section, total CH
                                <E T="52">4</E>
                                 mass, in metric tons CH
                                <E T="52">4</E>
                                , that was recovered during the calendar year using a vapor recovery system.
                            </P>
                            <P>(xv) For the atmospheric pressure storage tanks identified in paragraph (j)(1)(x)(F) of this section, the total volume of gas vented through open thief hatches, in scf, during periods while the storage tanks were also routing emissions to vapor recovery systems and/or flares.</P>
                            <P>(2) If you used Calculation Method 3 to calculate GHG emissions, then you must report the information specified in paragraphs (j)(2)(i) through (iii) of this section.</P>
                            <P>(i) Report the information specified in paragraphs (j)(2)(i)(A) through (H) of this section, at the facility level, for atmospheric pressure storage tanks where emissions were calculated using Calculation Method 3 of § 98.233(j).</P>
                            <P>(A) The total annual hydrocarbon liquids throughput that is sent to all atmospheric pressure storage tanks in the facility with emissions calculated using Calculation Method 3, in barrels. You may delay reporting of this data element for onshore production if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells at the facility with hydrocarbon liquids production that send hydrocarbon liquids to atmospheric pressure storage tanks for which emissions were calculated using Calculation Method 3. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the total annual hydrocarbon liquids throughput from all wells and the well ID number(s) for the well(s) included in this volume.</P>
                            <P>
                                (B) The total annual produced water throughput that is sent to all atmospheric pressure storage tanks in the facility with emissions calculated using Calculation Method 3, in barrels, specified in paragraphs (j)(2)(i)(B)(
                                <E T="03">1</E>
                                ) through (
                                <E T="03">3</E>
                                ) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) Total volume of produced water with pressure less than or equal to 50 psi.
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) Total volume of produced water with pressure greater than 50 psi and less than or equal to 250 psi.
                            </P>
                            <P>
                                (
                                <E T="03">3</E>
                                ) Total volume of produced water with pressure greater than 250 psi.
                            </P>
                            <P>(C) An estimate of the fraction of hydrocarbon liquids throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric pressure storage tanks in the facility that controlled emissions with flares.</P>
                            <P>(D) An estimate of the fraction of hydrocarbon liquids throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric pressure storage tanks in the facility that controlled emissions with vapor recovery systems.</P>
                            <P>(E) An estimate of the fraction of total produced water throughput reported in paragraph (j)(2)(i)(B) of this section sent to atmospheric pressure storage tanks in the facility that controlled emissions with flares.</P>
                            <P>(F) An estimate of the fraction of total produced water throughput reported in paragraph (j)(2)(i)(B) of this section sent to atmospheric pressure storage tanks in the facility that controlled emissions with vapor recovery systems.</P>
                            <P>(G) The number of fixed roof atmospheric pressure storage tanks in the facility.</P>
                            <P>(H) The number of floating roof atmospheric pressure storage tanks in the facility.</P>
                            <P>(ii) Report the information specified in paragraphs (j)(2)(ii)(A) through (H) of this section for each well-pad site (for onshore production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments) with atmospheric pressure storage tanks receiving hydrocarbon liquids whose emissions were calculated using § 98.233(j)(3)(i).</P>
                            <P>(A) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(B) The number of atmospheric pressure storage tanks that did not control emissions with flares and for which emissions were calculated using Calculation Method 3.</P>
                            <P>(C) The number of atmospheric pressure storage tanks that controlled emissions with flares and for which emissions were calculated using Calculation Method 3.</P>
                            <P>(D) The number of atmospheric pressure storage tanks that had an open thief hatch at some point during the year while the storage tank was also routing emissions to a vapor recovery system and/or a flare.</P>
                            <P>(E) The total number of separators, wells, or non-separator equipment with annual average daily hydrocarbon liquids throughput greater than 0 barrels per day and less than 10 barrels per day for which you used Calculation Method 3 (“Count” from equation W-15A to § 98.233).</P>
                            <P>
                                (F) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , that resulted from venting gas directly to the atmosphere, calculated using equation W-15A to § 98.233 and adjusted using the requirements described in § 98.233(j)(4), if applicable.
                            </P>
                            <P>
                                (G) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , that resulted from venting gas directly to the atmosphere, calculated using equation W-15A to § 98.233 and adjusted using the requirements described in § 98.233(j)(4), if applicable.
                            </P>
                            <P>(H) The total volume of gas vented through open thief hatches, in scf, during periods while the atmospheric pressure storage tanks were also routing emissions to vapor recovery systems and/or flares.</P>
                            <P>(iii) Report the information specified in paragraphs (j)(2)(iii)(A) through (F) of this section for each well-pad site (for onshore production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for onshore natural gas processing) with atmospheric pressure storage tanks receiving produced water whose emissions were calculated using § 98.233(j)(3)(ii).</P>
                            <P>(A) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>
                                (B) The number of atmospheric pressure storage tanks that did not control emissions with flares and for which emissions were calculated using Calculation Method 3.
                                <PRTPAGE P="42308"/>
                            </P>
                            <P>(C) The number of atmospheric pressure storage tanks that controlled emissions with flares and for which emissions were calculated using Calculation Method 3.</P>
                            <P>(D) The number of atmospheric pressure storage tanks that had an open thief hatch at some point during the year while the storage tank was also routing emissions to a vapor recovery system and/or a flare.</P>
                            <P>
                                (E) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , that resulted from venting gas directly to the atmosphere, calculated using equation W-15B to § 98.233 and adjusted using the requirements described in § 98.233(j)(4), if applicable.
                            </P>
                            <P>(F) The total volume of gas vented through open thief hatches, in scf, during periods while the atmospheric pressure storage tanks were also routing emissions to vapor recovery systems and/or flares.</P>
                            <P>(3) If you used Calculation Method 1 or Calculation Method 2 of § 98.233(j), and any gas-liquid separator liquid dump values did not close properly during the calendar year, then you must report the information specified in paragraphs (j)(3)(i) through (v) of this section for each well-pad site (for onshore production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments) by liquid type.</P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) The total number of gas-liquid separators whose liquid dump valves did not close properly during the calendar year.</P>
                            <P>
                                (iii) The total time the dump valves on gas-liquid separators did not close properly in the calendar year, in hours (sum of the “T
                                <E T="52">dv</E>
                                ” values used in equation W-16 to § 98.233).
                            </P>
                            <P>
                                (iv) For atmospheric pressure storage tanks receiving hydrocarbon liquids, annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , that resulted from dump valves on gas-liquid separators not closing properly during the calendar year, calculated using equation W-16 to § 98.233.
                            </P>
                            <P>
                                (v) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , that resulted from the dump valves on gas-liquid separators not closing properly during the calendar year, calculated using equation W-16 to § 98.233.
                            </P>
                            <P>(4) For atmospheric pressure storage tanks that were routed to flares, report the information specified in paragraphs (j)(4)(i) through (iv) of this section.</P>
                            <P>(i) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(j) as specified in § 98.233(n)(3)(ii)(B).</P>
                            <P>(ii) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.</P>
                            <P>(iii) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section to which the atmospheric pressure storage tank vent was routed.</P>
                            <P>(iv) The unique ID for the stream routed to the flare as specified in paragraph (n)(3) of this section from the atmospheric pressure storage tank.</P>
                            <P>(k) Condensate storage tanks. You must indicate whether your facility contains any condensate storage tanks. If your facility contains at least one condensate storage tank, then you must report the information specified in paragraphs (k)(1) and (2) of this section for each condensate storage tank vent stack.</P>
                            <P>(1) For each condensate storage tank vent stack, report the information specified in (k)(1)(i) through (iv) of this section.</P>
                            <P>(i) The unique name or ID number for the condensate storage tank vent stack.</P>
                            <P>(ii) Indicate if a flare is attached to the condensate storage tank vent stack.</P>
                            <P>(iii) Indicate whether scrubber dump valve leakage occurred for the condensate storage tank vent according to § 98.233(k)(1).</P>
                            <P>(iv) Which method specified in § 98.233(k)(1) was used to determine if dump valve leakage occurred.</P>
                            <P>(2) If scrubber dump valve leakage occurred for a condensate storage tank vent stack, as reported in paragraph (k)(1)(iii) of this section, and the vent stack vented directly to the atmosphere during the calendar year, then you must report the information specified in paragraphs (k)(2)(i) through (v) of this section for each condensate storage vent stack where scrubber dump valve leakage occurred.</P>
                            <P>(i) Which method specified in § 98.233(k)(2) was used to measure the leak rate.</P>
                            <P>(ii) Measured leak rate (average leak rate from a continuous flow measurement device), in standard cubic feet per hour.</P>
                            <P>(iii) Duration of time that the leak is counted as having occurred, in hours, as determined in § 98.233(k)(3) (may use best available data if a continuous flow measurement device was used).</P>
                            <P>
                                (iv) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , that resulted from venting gas directly to the atmosphere, calculated according to § 98.233(k)(1) through (4).
                            </P>
                            <P>
                                (v) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , that resulted from venting gas directly to the atmosphere, calculated according to § 98.233(k)(1) through (4).
                            </P>
                            <P>
                                (l) 
                                <E T="03">Well testing.</E>
                                 You must indicate whether you performed gas well or oil well testing, and if the testing of gas wells or oil wells resulted in vented or flared emissions during the calendar year. If you performed well testing that resulted in vented or flared emissions during the calendar year, then you must report the information specified in paragraphs (l)(1) through (4) of this section, as applicable.
                            </P>
                            <P>(1) For oil wells not routed to a flare, you must report the information specified in paragraphs (l)(1)(i) through (vii) of this section for each well tested.</P>
                            <P>(i) [Reserved]</P>
                            <P>(ii) Well ID number.</P>
                            <P>(iii) Number of well testing days for the tested well in the calendar year.</P>
                            <P>(iv) Average gas to oil ratio for the tested well, in cubic feet of gas per barrel of oil. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the average gas to oil ratio for the tested well.</P>
                            <P>(v) Average flow rate for the tested well, in barrels of oil per day. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured average flow rate for the tested well.</P>
                            <P>
                                (vi) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , calculated according to § 98.233(l).
                            </P>
                            <P>
                                (vii) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , calculated according to § 98.233(l).
                            </P>
                            <P>
                                (2) For oil wells routed to a flare and where you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (l)(2)(i) through (ii) and (ix) of this section, for each well tested. For oil wells routed to a flare and where you calculated natural gas emissions routed 
                                <PRTPAGE P="42309"/>
                                to the flare using the calculation methods in § 98.233(l) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (l)(2)(i) through (v) and (ix) of this section. All reported data elements should be specific to the well for which equation W-17A to § 98.233 was used and for which well testing emissions were routed to flares.
                            </P>
                            <P>(i) [Reserved]</P>
                            <P>(ii) Well ID number.</P>
                            <P>(iii) Number of well testing days for the tested well in the calendar year.</P>
                            <P>(iv) Average gas to oil ratio for the tested well, in cubic feet of gas per barrel of oil. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the average gas to oil ratio for the tested well.</P>
                            <P>(v) Average flow rate for the tested well, in barrels of oil per day. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured average flow rate for the tested well.</P>
                            <P>(vi) [Reserved]</P>
                            <P>(vii)[Reserved]</P>
                            <P>(viii) [Reserved]</P>
                            <P>(ix) Indicate whether natural gas emissions from well testing were routed to a flare and emissions are reported according to paragraph (n) of this section, and if so, provide the information specified in paragraphs (l)(2)(ix)(A) through (D).</P>
                            <P>(A) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(l) as specified in § 98.233(n)(3)(ii)(B).</P>
                            <P>(B) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.</P>
                            <P>(C) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section.</P>
                            <P>(D) The unique ID for each stream routed to the flare as specified in paragraph (n)(3) of this section.</P>
                            <P>(3) For gas wells not routed to a flare, you must report the information specified in paragraphs (l)(3)(i) through (vi) of this section for each well tested.</P>
                            <P>(i) [Reserved]</P>
                            <P>(ii) Well ID number.</P>
                            <P>(iii) Number of well testing days for the tested well(s) in the calendar year. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the number of well testing days for the tested well.</P>
                            <P>(iv) Average annual production rate for the tested well, in actual cubic feet per day. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured average annual production rate for the tested well.</P>
                            <P>
                                (v) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , calculated according to § 98.233(l).
                            </P>
                            <P>
                                (vi) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , calculated according to § 98.233(l).
                            </P>
                            <P>(4) For gas wells routed to a flare and where you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (l)(4)(i) through (ii) and (viii) of this section, for each well tested. For gas wells routed to a flare and where you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(l) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (l)(4)(i) through (iv) and (viii) of this section for each well tested. All reported data elements should be specific to the well for which equation W-17B to § 98.233 was used and for which well testing emissions were routed to flares.</P>
                            <P>(i) [Reserved]</P>
                            <P>(ii) Well ID number.</P>
                            <P>(iii) Number of well testing days for the tested well in the calendar year. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the number of well testing days for the tested well.</P>
                            <P>(iv) Average annual production rate for the tested well, in actual cubic feet per day. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well and/or delineation well and the only wells that are tested in the same basin are wildcat wells and/or delineation wells. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured average annual production rate for the tested well.</P>
                            <P>(v) [Reserved]</P>
                            <P>(vi)[Reserved]</P>
                            <P>(vii) [Reserved]</P>
                            <P>(viii) Indicate whether natural gas emissions from well testing were routed to a flare and emissions are reported according to paragraph (n) of this section, and if so, provide the information specified in paragraphs (l)(4)(viii)(A) through (D).</P>
                            <P>(A) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(l) as specified in § 98.233(n)(3)(ii)(B).</P>
                            <P>(B) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.</P>
                            <P>(C) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section.</P>
                            <P>(D) The unique ID for each stream routed to the flare as specified in paragraph (n)(3) of this section.</P>
                            <P>
                                (m) Associated natural gas. You must indicate whether any associated gas was vented or flared during the calendar year. If associated gas was vented during the calendar year, then you must report the information specified in paragraphs (m)(1) through (7) of this section for each well for which associated gas was vented. If associated gas was flared during the calendar year and you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (m)(1) through (3) of this section, for each well. If associated gas was flared and you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(m) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then 
                                <PRTPAGE P="42310"/>
                                you must report the information specified in paragraphs (m)(1) through (6) of this section for each well.
                            </P>
                            <P>(1) Well ID number.</P>
                            <P>(2) Indicate whether any associated gas was vented directly to the atmosphere without flaring.</P>
                            <P>(3) Indicate whether any associated gas was flared and emissions are reported according to paragraph (n) of this section, and, if so, provide the information specified in paragraphs (m)(3)(i) through (iv).</P>
                            <P>(i) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(m) as specified in § 98.233(n)(3)(ii)(B).</P>
                            <P>(ii) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.</P>
                            <P>(iii) The unique name or ID for the flare stack to which associated natural gas is routed as specified in paragraph (n)(1) of this section.</P>
                            <P>(iv) The unique ID for each associated natural gas stream routed to the flare as specified in paragraph (n)(3) of this section.</P>
                            <P>
                                (4) Average gas to oil ratio, in standard cubic feet of gas per barrel of oil during the reporting year. Do not report the GOR if you vented or flared associated gas and used a continuous flow monitor to determine the total volume of associated gas vented or routed to the flare (
                                <E T="03">i.e.</E>
                                , if you did not use equation W-18 to § 98.233 for the well with associated gas venting or flaring emissions).
                            </P>
                            <P>
                                (5) Volume of oil produced by the well, in barrels, in the calendar year only during the time periods in which associated gas was vented or flared (“V
                                <E T="52">p</E>
                                ” used in equation W-18 to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the volume of oil produced by the well during the time periods in which associated gas venting and flaring was occurring. Do not report the volume of oil produced if you vented or flared associated gas and used a continuous flow monitor to determine the total volume of associated gas vented or routed to the flare (
                                <E T="03">i.e.</E>
                                , if you did not use equation W-18 to § 98.233 for the well with associated gas venting or flaring emissions).
                            </P>
                            <P>
                                (6) Total volume of associated gas sent to sales or used on site and not sent to a vent or flare, in standard cubic feet, in the calendar year only during time periods in which associated gas was vented or flared (“SG” value used in equation W-18 to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured total volume of associated gas sent to sales for the well during the time periods in which associated gas venting and flaring was occurring. Do not report the volume of gas sent to sales if you vented or flared associated gas and used a continuous flow monitor to determine the total volume of associated gas vented or routed to the flare (
                                <E T="03">i.e.</E>
                                , if you did not use equation W-18 to § 98.233).
                            </P>
                            <P>(7) If you had associated gas emissions vented directly to the atmosphere without flaring, then you must report the information specified in paragraphs (m)(7)(i) through (viii) of this section for each well.</P>
                            <P>(i) [Reserved]</P>
                            <P>(ii) Indicate whether the associated gas volume vented from the well was measured using a continuous flow monitor.</P>
                            <P>(iii) Indicate whether associated gas streams vented from the well were measured with continuous gas composition analyzers.</P>
                            <P>(iv) Total volume of associated gas vented from the well, in standard cubic feet.</P>
                            <P>
                                (v) Flow-weighted average mole fraction of CH
                                <E T="52">4</E>
                                 in associated gas vented from the well.
                            </P>
                            <P>
                                (vi) Flow-weighted average mole fraction of CO
                                <E T="52">2</E>
                                 in associated gas vented from the well.
                            </P>
                            <P>
                                (vii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , calculated according to § 98.233(m)(3) and (4).
                            </P>
                            <P>
                                (viii) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , calculated according to § 98.233(m)(3) and (4).
                            </P>
                            <P>
                                (n) 
                                <E T="03">Flare stacks.</E>
                                 You must indicate if your facility has any flare stacks. You must report the information specified in paragraphs (n)(1) through (20) of this section for each flare stack at your facility.
                            </P>
                            <P>(1) Unique name or ID for the flare stack. For the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments, a different name or ID may be used for a single flare stack for each location where it operates at in a given calendar year.</P>
                            <P>(2) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>
                                (3) Unique IDs for each stream routed to the flare and the source type that generated the stream, if you determine the flow of each stream that is routed to the flare as specified in § 98.233(n)(3)(ii) and/or you determine the gas composition for each stream routed to the flare as specified in § 98.233(n)(4)(iii). If you determine flow or composition for a combined stream from multiple source types, then report the source type that provides the most gas to the combined stream. For source types not listed in § 98.233(n)(3)(ii)(B)(
                                <E T="03">1</E>
                                ) through (
                                <E T="03">7</E>
                                ), report collectively as “other.”
                            </P>
                            <P>
                                (4) Indicate the type of flare (
                                <E T="03">i.e.</E>
                                , open ground-level flare, enclosed ground-level flare, open elevated flare, or enclosed elevated flare).
                            </P>
                            <P>
                                (5) Indicate the type of flare assist (
                                <E T="03">i.e.</E>
                                , unassisted, air-assisted with single speed fan/blower, air-assisted with dual speed fan/blower, air-assisted with variable speed fan/blower, steam-assisted, or pressure-assisted).
                            </P>
                            <P>(6) Indicate whether the pilot flame or combustion flame was monitored continuously, visually inspected, or both. If visually inspected, report the number of inspections during the year. If the pilot flame was monitored continuously, report the number of times all continuous monitoring devices were out of service or otherwise inoperable for a period of more than one week.</P>
                            <P>(7) Indicate whether you measured total flow at the inlet to the flare as specified in § 98.233(n)(3)(i) or whether you determined flow for individual streams routed to the flare as specified in § 98.233(n)(3)(ii). If you measured total flow, indicate whether the volume of gas was determined using a continuous flow measurement device or whether it was determined using parameter monitoring and engineering calculations. If you determined flow for individual streams, indicate for each stream whether flow was determined using a continuous flow measurement device, parameter monitoring and engineering calculations, or other simulation or engineering calculation methods. If you switched from one method to another during the year, then indicate multiple methods were used.</P>
                            <P>
                                (8) Indicate whether a continuous gas composition analyzer was used at the inlet to the flare as specified in 
                                <PRTPAGE P="42311"/>
                                § 98.233(n)(4)(i), whether composition at the inlet to the flare was determined based on sampling and analysis as specified in § 98.233(n)(4)(ii), or if composition was determined for individual streams as specified in § 98.233(n)(4)(iii). If you determined composition for individual streams, indicate for each stream whether composition was determined using a continuous gas composition analyzer, sampling and analysis, or other simulation or engineering calculation methods. If you switched from one method to another during the year, then indicate multiple methods were used.
                            </P>
                            <P>(9) Indicate whether you directly measured annual average HHV of the inlet stream to the flare as specified in § 98.233(n)(8)(i), calculated the annual average HHV of the inlet stream to the flare based on composition of the inlet stream as specified in § 98.233(n)(8)(ii), directly measured the annual average HHV of individual streams routed to the flare as specified in § 98.233(n)(8)(iii), or calculated the annual average HHV of individual streams based on their composition as specified in § 98.233(n)(8)(iv).</P>
                            <P>
                                (10) Annual average HHV of the inlet stream to the flare determined as specified in § 98.233(n)(8)(i) or (ii); both the calculated flow-weighted annual average HHV of the inlet stream to the flare and each individual stream HHV determined as specified in § 98.233(n)(8)(iii)(B) or (iv)(B); or each individual stream HHV, if you determined HHVs for each individual stream routed to the flare and you used these HHVs to calculate N
                                <E T="52">2</E>
                                O emissions for each stream as specified in § 98.233(n)(8)(iii)(A) or (iv)(A).
                            </P>
                            <P>
                                (11) Volume of gas sent to the flare, in standard cubic feet (“V
                                <E T="52">s</E>
                                ” in equations W-19 and W-20 to § 98.233, where V
                                <E T="52">s</E>
                                 is the total flow at the flare inlet if you measure inlet flow to the flare in accordance with § 98.233(n)(3)(i) or the sum of the V
                                <E T="52">s</E>
                                 values for individual streams if you measure or determine flow of individual streams in accordance with § 98.233(n)(3)(ii)). If you measure or determine the volume of gas for each stream routed to the flare as specified in § 98.233(n)(3)(ii), then also report the annual volume of each stream, adjusted to exclude any estimated volume that bypassed the flare or determined to have leaked from the closed vent system, and indicate that the flow has been adjusted to account for bypass volume or leaks.
                            </P>
                            <P>
                                (12) Fraction of the feed gas sent to an un-lit flare based on total time when continuous monitoring of the pilot or periodic inspections indicated the flare was not lit and measured or calculated flow during the times when the flare was not lit (“Z
                                <E T="52">U</E>
                                ” in equation W-19 to § 98.233).
                            </P>
                            <P>
                                (13) Flare destruction efficiency, expressed as the fraction of hydrocarbon compounds in gas that is destroyed by a burning flare, but may or may not be completely oxidized to CO
                                <E T="52">2</E>
                                 (§ 98.233(n)(1)). If you used multiple methods during the year, report the flow-weighted average destruction efficiency based on each tier that applied. Report the efficiency fraction to three decimal places.
                            </P>
                            <P>(i) If you use tier 1, report the following:</P>
                            <P>(A) Number of days in periods of 15 or more consecutive days when you did not conform with all cited provisions in § 98.233(n)(1)(i).</P>
                            <P>(B) [Reserved]</P>
                            <P>(ii) If you use tier 2, report the following:</P>
                            <P>(A) Indicate if you are subject to part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or if you are electing to comply with the flare monitoring requirements in part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter.</P>
                            <P>(B) If you are not required to comply with part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, indicate whether you are electing to comply with § 98.233(n)(1)(ii)(A), (B), (C), or (D).</P>
                            <P>(C) If you are not required to comply with part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter and the flare is an enclosed ground level flare or an enclosed elevated flare, indicate if your most recent performance test was conducted using the method in § 60.5413b(b) of this chapter (as specified in § 98.233(n)(1)(ii)(A)), the method in § 60.5413b(d) of this chapter (as specified in § 98.233(n)(1)(ii)(C)), or if it was conducted using OTM-52.</P>
                            <P>(D) Number of days in periods of 15 or more consecutive days when you did not conform with all cited provisions in § 98.233(n)(1)(ii).</P>
                            <P>(iii) Indicate if you use an alternative test method approved under § 60.5412b(d) of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter. If you use an approved alternative test method, indicate the approved destruction efficiency for the method, the date when you started to use the method, and the name or ID of the method.</P>
                            <P>
                                (14) Annual average mole fraction of CH
                                <E T="52">4</E>
                                 in the feed gas to the flare if you measure composition of the inlet gas as specified in § 98.233(n)(3)(i) or (ii) (“X
                                <E T="52">CH4</E>
                                ” in equation W-19 to § 98.233), or the annual average CH
                                <E T="52">4</E>
                                 mole fractions for each stream if you determine composition of each stream routed to the flare as specified in § 98.233(n)(4)(iii).
                            </P>
                            <P>
                                (15) Except as specified in paragraph (n)(20) of this section, annual average mole fraction of CO
                                <E T="52">2</E>
                                 in the feed gas to the flare if you measure composition of the inlet gas as specified in § 98.233(n)(4)(i) or (ii) (“X
                                <E T="52">CO2</E>
                                ” in equation W-20 to § 98.233), or the annual average CO
                                <E T="52">2</E>
                                 mole fractions for each stream if you determine composition of each stream routed to the flare as specified in § 98.233(n)(4)(iii).
                            </P>
                            <P>
                                (16) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                 (refer to equation W-20 to § 98.233).
                            </P>
                            <P>
                                (17) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                 (refer to equation W-19 to § 98.233).
                            </P>
                            <P>
                                (18) Annual N
                                <E T="52">2</E>
                                O emissions, in metric tons N
                                <E T="52">2</E>
                                O (refer to equation W-40 to § 98.233).
                            </P>
                            <P>
                                (19) Estimated disaggregated CH
                                <E T="52">4</E>
                                , CO
                                <E T="52">2</E>
                                , and N
                                <E T="52">2</E>
                                O emissions attributed to each source type as determined in § 98.233(n)(10) (
                                <E T="03">i.e.</E>
                                , AGR vents, dehydrator vents, well venting during completions and workovers with hydraulic fracturing, gas well venting during completions and workovers without hydraulic fracturing, hydrocarbon liquids and produced water storage tanks, well testing venting and flaring, associated gas venting and flaring, other flared sources).
                            </P>
                            <P>
                                (20) Indicate whether a CEMS was used to measure emissions from the flare. If a CEMS was used, then you are not required to report the CO
                                <E T="52">2</E>
                                 mole fraction in paragraph (n)(15) of this section.
                            </P>
                            <P>
                                (o) 
                                <E T="03">Centrifugal compressors.</E>
                                 You must indicate whether your facility has centrifugal compressors. You must report the information specified in paragraphs (o)(1) and (2) of this section for all centrifugal compressors at your facility. For each compressor source or manifolded group of compressor sources that you conduct as found leak measurements as specified in § 98.233(o)(2) or (4), you must report the information specified in paragraph (o)(3) of this section. For each compressor source or manifolded group of compressor sources that you conduct continuous monitoring as specified in § 98.233(o)(3) or (5), you must report the information specified in paragraph (o)(4) of this section. Centrifugal 
                                <PRTPAGE P="42312"/>
                                compressors in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting that calculate emissions according to § 98.233(o)(10)(iii) are not required to report information in paragraphs (o)(1) through (4) of this section and instead must report the information specified in paragraph (o)(5) of this section.
                            </P>
                            <P>
                                (1) 
                                <E T="03">Compressor activity data.</E>
                                 Report the information specified in paragraphs (o)(1)(i) through (xi) of this section, as applicable, for each centrifugal compressor located at your facility.
                            </P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) Unique name or ID for the centrifugal compressor.</P>
                            <P>(iii) Hours in operating-mode.</P>
                            <P>(iv) Hours in standby-pressurized-mode.</P>
                            <P>(v) Hours in not-operating-depressurized-mode.</P>
                            <P>(vi) If you conducted volumetric emission measurements as specified in § 98.233(o)(1):</P>
                            <P>(A) Indicate whether the compressor was measured in operating-mode.</P>
                            <P>(B) Indicate whether the compressor was measured in standby-pressurized-mode.</P>
                            <P>(C) Indicate whether the compressor was measured in not-operating-depressurized-mode.</P>
                            <P>(vii) Indicate whether the compressor has blind flanges installed and associated dates.</P>
                            <P>(viii) Indicate whether the compressor has wet or dry seals.</P>
                            <P>(ix) If the compressor has wet seals, the number of wet seals.</P>
                            <P>(x) If the compressor has dry seals, the number of dry seals.</P>
                            <P>(xi) Power output of the compressor driver (hp).</P>
                            <P>
                                (2) 
                                <E T="03">Compressor source.</E>
                                 (i) For each compressor source at each compressor, report the information specified in paragraphs (o)(2)(i)(A) through (C) of this section.
                            </P>
                            <P>(A) Centrifugal compressor name or ID. Use the same ID as in paragraph (o)(1)(ii) of this section.</P>
                            <P>(B) Centrifugal compressor source (wet seal, dry seal, isolation valve, or blowdown valve).</P>
                            <P>(C) Unique name or ID for the leak or vent. If the leak or vent is connected to a manifolded group of compressor sources, use the same leak or vent ID for each compressor source in the manifolded group. If multiple compressor sources are released through a single vent for which continuous measurements are used, use the same leak or vent ID for each compressor source released via the measured vent. For a single compressor using as found measurements, you must provide a different leak or vent ID for each compressor source.</P>
                            <P>(ii) For each leak or vent, report the information specified in paragraphs (o)(2)(ii)(A) through (E) of this section.</P>
                            <P>(A) Indicate whether the leak or vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the leak or vent are released to the atmosphere, routed to a flare, combustion, or vapor recovery system.</P>
                            <P>(B) Indicate whether an as found measurement(s) as identified in § 98.233(o)(2) or (4) was conducted on the leak or vent.</P>
                            <P>(C) Indicate whether continuous measurements as identified in § 98.233(o)(3) or (5) were conducted on the leak or vent.</P>
                            <P>
                                (D) Report emissions as specified in paragraphs (o)(2)(ii)(D)(
                                <E T="03">1</E>
                                ) and (
                                <E T="03">2</E>
                                ) of this section for the leak or vent. If the leak or vent is routed to a flare, combustion, or vapor recovery system, you are not required to report emissions under this paragraph.
                            </P>
                            <P>
                                (1) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                .
                            </P>
                            <P>
                                (2) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                .
                            </P>
                            <P>(E) If the leak or vent is routed to flare, combustion, or vapor recovery system, report the percentage of time that the respective device was operational when the compressor source emissions were routed to the device.</P>
                            <P>
                                (3) 
                                <E T="03">As found measurement sample data.</E>
                                 If the measurement methods specified in § 98.233(o)(2) or (4) are conducted, report the information specified in paragraph (o)(3)(i) of this section. If the calculation specified in § 98.233(o)(6)(ii) is performed, report the information specified in paragraph (o)(3)(ii) of this section.
                            </P>
                            <P>(i) For each as found measurement performed on a leak or vent, report the information specified in paragraphs (o)(3)(i)(A) through (F) of this section.</P>
                            <P>(A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of this section.</P>
                            <P>(B) Measurement date.</P>
                            <P>(C) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions.</P>
                            <P>(D) Measured flow rate, in standard cubic feet per hour.</P>
                            <P>(E) For each compressor attached to the leak or vent, report the compressor mode during which the measurement was taken.</P>
                            <P>(F) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.</P>
                            <P>(ii) For each compressor mode-source combination where a reporter emission factor as calculated in equation W-23 to § 98.233 was used to calculate emissions in equation W-22 to § 98.233, report the information specified in paragraphs (o)(3)(ii)(A) through (D) of this section.</P>
                            <P>(A) The compressor mode-source combination.</P>
                            <P>
                                (B) The compressor mode-source combination reporter emission factor, in standard cubic feet per hour (EF
                                <E T="52">s,m</E>
                                 in equation W-23 to § 98.233).
                            </P>
                            <P>
                                (C) The total number of compressors measured in the compressor mode-source combination in the current reporting year and the preceding two reporting years (Count
                                <E T="52">m</E>
                                 in equation W-23 to § 98.233).
                            </P>
                            <P>(D) Indicate whether the compressor mode-source combination reporter emission factor is facility-specific or based on all of the reporter's applicable facilities.</P>
                            <P>
                                (4) 
                                <E T="03">Continuous measurement data.</E>
                                 If the measurement methods specified in § 98.233(o)(3) or (5) are conducted, report the information specified in paragraphs (o)(4)(i) through (iv) of this section for each continuous measurement conducted on each leak or vent associated with each compressor source or manifolded group of compressor sources.
                            </P>
                            <P>(i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of this section.</P>
                            <P>(ii) Measured volume of flow during the reporting year, in million standard cubic feet.</P>
                            <P>(iii) Indicate whether the measured volume of flow during the reporting year includes compressor blowdown emissions as allowed for in § 98.233(o)(3)(ii) and (o)(5)(iii).</P>
                            <P>(iv) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.</P>
                            <P>
                                (5) 
                                <E T="03">Onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting.</E>
                                 Centrifugal compressors with wet seal degassing vents in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting that calculate emissions 
                                <PRTPAGE P="42313"/>
                                according to § 98.233(o)(10)(iii) must report the information specified in paragraphs (o)(5)(i) through (iv) of this section. You must report the information specified in paragraphs (o)(5)(i) through (iv) of this section, as applicable, for each well-pad site (for onshore petroleum and natural gas production) or each gathering and boosting site (for onshore petroleum and natural gas gathering and boosting).
                            </P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) Report the following activity data.</P>
                            <P>(A) Total number of centrifugal compressors at the facility.</P>
                            <P>(B) Number of centrifugal compressors that have wet seals.</P>
                            <P>
                                (C) Number of centrifugal compressors that have atmospheric wet seal oil degassing vents (
                                <E T="03">i.e.</E>
                                , wet seal oil degassing vents where the emissions are released to the atmosphere rather than being routed to flares, combustion, or vapor recovery systems).
                            </P>
                            <P>
                                (iii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , from centrifugal compressors with atmospheric wet seal oil degassing vents.
                            </P>
                            <P>
                                (iv) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , from centrifugal compressors with atmospheric wet seal oil degassing vents.
                            </P>
                            <P>
                                (p) 
                                <E T="03">Reciprocating compressors.</E>
                                 You must indicate whether your facility has reciprocating compressors. You must report the information specified in paragraphs (p)(1) and (2) of this section for all reciprocating compressors at your facility. For each compressor source or manifolded group of compressor sources that you conduct as found leak measurements as specified in § 98.233(p)(2) or (4), you must report the information specified in paragraph (p)(3) of this section. For each compressor source or manifolded group of compressor sources that you conduct continuous monitoring as specified in § 98.233(p)(3) or (5), you must report the information specified in paragraph (p)(4) of this section. Reciprocating compressors in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting that calculate emissions according to § 98.233(p)(10)(iii) are not required to report information in paragraphs (p)(1) through (4) of this section and instead must report the information specified in paragraph (p)(5) of this section.
                            </P>
                            <P>
                                (1) 
                                <E T="03">Compressor activity data.</E>
                                 Report the information specified in paragraphs (p)(1)(i) through (viii) of this section, as applicable, for each reciprocating compressor located at your facility.
                            </P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) Unique name or ID for the reciprocating compressor.</P>
                            <P>(iii) Hours in operating-mode.</P>
                            <P>(iv) Hours in standby-pressurized-mode.</P>
                            <P>(v) Hours in not-operating-depressurized-mode.</P>
                            <P>(vi) If you conducted volumetric emission measurements as specified in § 98.233(p)(1):</P>
                            <P>(A) Indicate whether the compressor was measured in operating-mode.</P>
                            <P>(B) Indicate whether the compressor was measured in standby-pressurized-mode.</P>
                            <P>(C) Indicate whether the compressor was measured in not-operating-depressurized-mode.</P>
                            <P>(vii) Indicate whether the compressor has blind flanges installed and associated dates.</P>
                            <P>(viii) Power output of the compressor driver (hp).</P>
                            <P>
                                (2) 
                                <E T="03">Compressor source.</E>
                                 (i) For each compressor source at each compressor, report the information specified in paragraphs (p)(2)(i)(A) through (C) of this section.
                            </P>
                            <P>(A) Reciprocating compressor name or ID. Use the same ID as in paragraph (p)(1)(i) of this section.</P>
                            <P>(B) Reciprocating compressor source (isolation valve, blowdown valve, or rod packing).</P>
                            <P>(C) Unique name or ID for the leak or vent. If the leak or vent is connected to a manifolded group of compressor sources, use the same leak or vent ID for each compressor source in the manifolded group. If multiple compressor sources are released through a single vent for which continuous measurements are used, use the same leak or vent ID for each compressor source released via the measured vent. For a single compressor using as found measurements, you must provide a different leak or vent ID for each compressor source.</P>
                            <P>(ii) For each leak or vent, report the information specified in paragraphs (p)(2)(ii)(A) through (E) of this section.</P>
                            <P>(A) Indicate whether the leak or vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the leak or vent are released to the atmosphere, routed to a flare, combustion, or vapor recovery system.</P>
                            <P>(B) Indicate whether an as found measurement(s) as identified in § 98.233(p)(2) or (4) was conducted on the leak or vent.</P>
                            <P>(C) Indicate whether continuous measurements as identified in § 98.233(p)(3) or (5) were conducted on the leak or vent.</P>
                            <P>
                                (D) Report emissions as specified in paragraphs (p)(2)(ii)(D)(
                                <E T="03">1</E>
                                ) and (
                                <E T="03">2</E>
                                ) of this section for the leak or vent. If the leak or vent is routed to a flare, combustion, or vapor recovery system, you are not required to report emissions under this paragraph.
                            </P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                .
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                .
                            </P>
                            <P>(E) If the leak or vent is routed to a flare, combustion, or vapor recovery system, report the percentage of time that the respective device was operational when the compressor source emissions were routed to the device.</P>
                            <P>
                                (3) 
                                <E T="03">As found measurement sample data.</E>
                                 If the measurement methods specified in § 98.233(p)(2) or (4) are conducted, report the information specified in paragraph (p)(3)(i) of this section. If the calculation specified in § 98.233(p)(6)(ii) is performed, report the information specified in paragraph (p)(3)(ii) of this section.
                            </P>
                            <P>(i) For each as found measurement performed on a leak or vent, report the information specified in paragraphs (p)(3)(i)(A) through (F) of this section.</P>
                            <P>(A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)(2)(i)(C) of this section.</P>
                            <P>(B) Measurement date.</P>
                            <P>(C) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions.</P>
                            <P>(D) Measured flow rate, in standard cubic feet per hour.</P>
                            <P>(E) For each compressor attached to the leak or vent, report the compressor mode during which the measurement was taken.</P>
                            <P>(F) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.</P>
                            <P>(ii) For each compressor mode-source combination where a reporter emission factor as calculated in equation W-28 to § 98.233 was used to calculate emissions in equation W-27 to § 98.233, report the information specified in paragraphs (p)(3)(ii)(A) through (D) of this section.</P>
                            <P>(A) The compressor mode-source combination.</P>
                            <P>
                                (B) The compressor mode-source combination reporter emission factor, in 
                                <PRTPAGE P="42314"/>
                                standard cubic feet per hour (EF
                                <E T="52">s,m</E>
                                 in equation W-28 to § 98.233).
                            </P>
                            <P>
                                (C) The total number of compressors measured in the compressor mode-source combination in the current reporting year and the preceding two reporting years (Count
                                <E T="52">m</E>
                                 in equation W-28 to § 98.233).
                            </P>
                            <P>(D) Indicate whether the compressor mode-source combination reporter emission factor is facility-specific or based on all of the reporter's applicable facilities.</P>
                            <P>
                                (4) 
                                <E T="03">Continuous measurement data.</E>
                                 If the measurement methods specified in § 98.233(p)(3) or (5) are conducted, report the information specified in paragraphs (p)(4)(i) through (iv) of this section for each continuous measurement conducted on each leak or vent associated with each compressor source or manifolded group of compressor sources.
                            </P>
                            <P>(i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)(2)(i)(C) of this section.</P>
                            <P>(ii) Measured volume of flow during the reporting year, in million standard cubic feet.</P>
                            <P>(iii) Indicate whether the measured volume of flow during the reporting year includes compressor blowdown emissions as allowed for in § 98.233(p)(3)(ii) and (p)(5)(iii).</P>
                            <P>(iv) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.</P>
                            <P>
                                (5) 
                                <E T="03">Onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting.</E>
                                 Reciprocating compressors in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting that calculate emissions according to § 98.233(p)(10)(iii) must report the information specified in paragraphs (p)(5)(i) through (iv) of this section. You must report the information specified in paragraphs (p)(5)(i) through (iv) of this section, as applicable, for each well-pad site (for onshore petroleum and natural gas production) or each gathering and boosting site (for onshore petroleum and natural gas gathering and boosting).
                            </P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) Report the following activity data.</P>
                            <P>(A) Total number of reciprocating compressors at the facility.</P>
                            <P>
                                (B) Number of reciprocating compressors that have rod packing emissions vented directly to the atmosphere (
                                <E T="03">i.e.</E>
                                , rod packing vents where the emissions are released to the atmosphere rather than being routed to flares, combustion, or vapor recovery systems).
                            </P>
                            <P>
                                (iii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , from reciprocating compressors with rod packing emissions vented directly to the atmosphere.
                            </P>
                            <P>
                                (iv) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , from reciprocating compressors with rod packing emissions vented directly to the atmosphere.
                            </P>
                            <P>
                                (q) 
                                <E T="03">Equipment leak surveys.</E>
                                 For any components subject to or complying with the requirements of § 98.233(q), you must report the information specified in paragraphs (q)(1) and (2) of this section. You must report the information specified in paragraphs (q)(1) and (2) of this section, as applicable, for each well-pad site (for onshore production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments). Natural gas distribution facilities with emission sources listed in § 98.232(i)(1) must also report the information specified in paragraph (q)(3) of this section.
                            </P>
                            <P>(1) You must report the information specified in paragraphs (q)(1)(i) through (ix) of this section.</P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) Except as specified in paragraph (q)(1)(iii) of this section, the number of complete equipment leak surveys performed during the calendar year.</P>
                            <P>(iii) Natural gas distribution facilities performing equipment leak surveys across a multiple year leak survey cycle must report the number of years in the leak survey cycle.</P>
                            <P>(iv) Except for natural gas distribution facilities and onshore natural gas transmission pipeline facilities, indicate whether any of the leak detection surveys used in calculating emissions per § 98.233(q)(2) were conducted for compliance with any of the standards in paragraphs (q)(1)(iv)(A) through (E) of this section. Report the indication per well-pad site, gathering and boosting site, or facility, not per component type, as applicable.</P>
                            <P>(A) The well site or compressor station fugitive emissions standards in § 60.5397a of this chapter.</P>
                            <P>(B) The well site, centralized production facility, or compressor station fugitive emissions standards in § 60.5397b or § 60.5398b of this chapter.</P>
                            <P>(C) The well site, centralized production facility, or compressor station fugitive emissions standards in an applicable approved state plan or applicable Federal plan in part 62 of this chapter.</P>
                            <P>(D) The standards for equipment leaks at onshore natural gas processing plants in § 60.5400b or § 60.5401b of this chapter.</P>
                            <P>(E) The standards for equipment leaks at onshore natural gas processing plants in an applicable approved state plan or applicable Federal plan in part 62 of this chapter.</P>
                            <P>(v) For facilities in onshore petroleum and natural gas production, onshore petroleum and natural gas gathering and boosting, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment, indicate whether you elected to comply with § 98.233(q) according to § 98.233(q)(1)(iv) for any equipment components at your well-pad site, gathering and boosting site, or facility.</P>
                            <P>(vi) Report each type of method described in § 98.234(a) that was used to conduct leak surveys.</P>
                            <P>(vii) Report whether emissions were calculated using Calculation Method 1 (leaker factor emission calculation methodology) and/or using Calculation Method 2 (leaker measurement methodology).</P>
                            <P>(viii) For facilities in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting, report the number of major equipment (as listed in table W-1 to this subpart) by service type for which leak detection surveys were conducted and emissions calculated according to § 98.233(q).</P>
                            <P>(ix) For facilities in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting, report the number of major equipment (as listed in table W-1 to this subpart) in vacuum service as defined in § 98.238.</P>
                            <P>
                                (2) You must indicate whether your facility contains any of the component types subject to or complying with § 98.233(q) that are listed in § 98.232(c)(21), (d)(7), (e)(7) or (8), (f)(5) through (8), (g)(4), (g)(6) or (7), (h)(5), (h)(7) or (8), (i)(1), (j)(10), (m)(3)(ii) or (m)(4)(ii) for your facility's industry segment. For each component type and leak detection method combination that is located at your well-pad site, gathering and boosting site, or facility, you must report the information specified in paragraphs (q)(2)(i) through (ix) of this section. If a component type is located at your well-pad site, gathering and boosting site, or facility 
                                <PRTPAGE P="42315"/>
                                and no leaks were identified from that component, then you must report the information in paragraphs (q)(2)(i) through (ix) of this section but report a zero (“0”) for the information required according to paragraphs (q)(2)(vi) through (ix) of this section. If you used Calculation Method 1 (leaker factor emission calculation methodology) for some complete leak surveys and used Calculation Method 2 (leaker measurement methodology) for some complete leak surveys, you must report the information specified in paragraphs (q)(2)(i) through (ix) of this section separately for component surveys using Calculation Method 1 and Calculation Method 2.
                            </P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) Component type.</P>
                            <P>
                                (iii) Leak detection method used for the screening survey (
                                <E T="03">e.g.</E>
                                , Method 21 as specified in § 98.234(a)(2)(i); Method 21 as specified in § 98.234(a)(2)(ii); and OGI and other leak detection methods as specified in § 98.234(a)(1), (3), or (5)).
                            </P>
                            <P>
                                (iv) Emission factor or measurement method used (
                                <E T="03">e.g.</E>
                                , default emission factor; site-specific emission factor developed according to § 98.233(q)(4); or direct measurement according to § 98.233(q)(3)).
                            </P>
                            <P>(v) Total number of components surveyed by type and leak detection method in the calendar year.</P>
                            <P>(vi) Total number of the surveyed component types by leak detection method that were identified as leaking in the calendar year (“xp” in equation W-30 to § 98.233 for the component type or the number of leaks measured for the specified component type according to the provisions in § 98.233(q)(3)).</P>
                            <P>
                                (vii) Average time the surveyed components are assumed to be leaking and operational, in hours (average of “T
                                <E T="52">p,z</E>
                                ” from equation W-30 to § 98.233 for the component type or average duration of leaks for the specified component type determined according to the provisions in § 98.233(q)(3)(ii)).
                            </P>
                            <P>
                                (viii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for the component type as calculated using equation W-30 to § 98.233 or § 98.233(q)(3)(vii) (for surveyed components only).
                            </P>
                            <P>
                                (ix) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for the component type as calculated using equation W-30 to § 98.233 or § 98.233(q)(3)(vii) (for surveyed components only).
                            </P>
                            <P>(3) Natural gas distribution facilities with emission sources listed in § 98.232(i)(1) must also report the information specified in paragraphs (q)(3)(i) through (viii) and, if applicable, (q)(3)(ix) of this section.</P>
                            <P>(i) Number of above grade transmission-distribution transfer stations surveyed in the calendar year.</P>
                            <P>
                                (ii) Number of meter/regulator runs at above grade transmission-distribution transfer stations surveyed in the calendar year (“Count
                                <E T="52">MR,y</E>
                                ” from equation W-31 to § 98.233, for the current calendar year).
                            </P>
                            <P>
                                (iii) Average time that meter/regulator runs surveyed in the calendar year were operational, in hours (average of “T
                                <E T="52">w,y</E>
                                ” from equation W-31 to § 98.233, for the current calendar year).
                            </P>
                            <P>(iv) Number of above grade transmission-distribution transfer stations surveyed in the current leak survey cycle.</P>
                            <P>
                                (v) Number of meter/regulator runs at above grade transmission-distribution transfer stations surveyed in current leak survey cycle (sum of “Count
                                <E T="52">MR,y</E>
                                ” from equation W-31 to § 98.233, for all calendar years in the current leak survey cycle).
                            </P>
                            <P>
                                (vi) Average time that meter/regulator runs surveyed in the current leak survey cycle were operational, in hours (average of “T
                                <E T="52">w,y</E>
                                ” from equation W-31 to § 98.233, for all years included in the leak survey cycle).
                            </P>
                            <P>
                                (vii) Meter/regulator run CO
                                <E T="52">2</E>
                                 emission factor based on all surveyed transmission-distribution transfer stations in the current leak survey cycle, in standard cubic feet of CO
                                <E T="52">2</E>
                                 per operational hour of all meter/regulator runs (“EF
                                <E T="52">s,MR,i</E>
                                ” for CO
                                <E T="52">2</E>
                                 calculated using equation W-31 to § 98.233).
                            </P>
                            <P>
                                (viii) Meter/regulator run CH
                                <E T="52">4</E>
                                 emission factor based on all surveyed transmission-distribution transfer stations in the current leak survey cycle, in standard cubic feet of CH
                                <E T="52">4</E>
                                 per operational hour of all meter/regulator runs (“EF
                                <E T="52">s,MR,i</E>
                                ” for CH
                                <E T="52">4</E>
                                 calculated using equation W-31 to § 98.233).
                            </P>
                            <P>(ix) If your natural gas distribution facility performs equipment leak surveys across a multiple year leak survey cycle, you must also report:</P>
                            <P>
                                (A) The total number of meter/regulator runs at above grade transmission-distribution transfer stations at your facility (“Count
                                <E T="52">MR</E>
                                ” in equation W-32B to § 98.233).
                            </P>
                            <P>
                                (B) Average estimated time that each meter/regulator run at above grade transmission-distribution transfer stations was operational in the calendar year, in hours per meter/regulator run (“T
                                <E T="52">w,avg</E>
                                ” in equation W-32B to § 98.233).
                            </P>
                            <P>
                                (C) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for all above grade transmission-distribution transfer stations at your facility.
                            </P>
                            <P>
                                (D) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for all above grade transmission-distribution transfer stations at your facility.
                            </P>
                            <P>
                                (r) 
                                <E T="03">Equipment leaks by population count.</E>
                                 If your facility is subject to the requirements of § 98.233(r), then you must report the information specified in paragraphs (r)(1) through (3) of this section, as applicable. You must report the information specified in paragraphs (r)(1) through (3) of this section, as applicable, for each well-pad site (for onshore petroleum and natural gas production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments).
                            </P>
                            <P>(1) You must indicate whether your facility contains any of the emission source types required to use equation W-32A to § 98.233. You must report the information specified in paragraphs (r)(1)(i) through (vi) of this section separately for each emission source type required to use equation W-32A to § 98.233 that is located at your facility. For each well-pad site and gathering and boosting site at onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities, you must report the information specified in paragraphs (r)(1)(i) through (vi) of this section separately by equipment type and service type.</P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) Emission source type. Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must report the equipment type and service type.</P>
                            <P>
                                (iii) Total number of the emission source type at the well-pad site, gathering and boosting site, or facility, as applicable (“Count
                                <E T="52">e</E>
                                ” in equation W-32A to § 98.233).
                            </P>
                            <P>
                                (iv) Average estimated time that the emission source type was operational in the calendar year, in hours (“T
                                <E T="52">e</E>
                                ” in equation W-32A to § 98.233).
                            </P>
                            <P>
                                (v) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , for the emission source type.
                            </P>
                            <P>
                                (vi) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , for the emission source type.
                            </P>
                            <P>
                                (2) Natural gas distribution facilities must also report the information specified in paragraphs (r)(2)(i) through (v) of this section.
                                <PRTPAGE P="42316"/>
                            </P>
                            <P>(i) Number of above grade transmission-distribution transfer stations at the facility.</P>
                            <P>(ii) Number of above grade metering-regulating stations that are not transmission-distribution transfer stations at the facility.</P>
                            <P>
                                (iii) Total number of meter/regulator runs at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations (“Count
                                <E T="52">MR</E>
                                ” in equation W-32B to § 98.233).
                            </P>
                            <P>
                                (iv) Average estimated time that each meter/regulator run at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations was operational in the calendar year, in hours per meter/regulator run (“T
                                <E T="52">w,avg</E>
                                ” in equation W-32B to § 98.233).
                            </P>
                            <P>(v) If your facility has above grade metering-regulating stations that are not above grade transmission-distribution transfer stations and your facility also has above grade transmission-distribution transfer stations, you must also report:</P>
                            <P>
                                (A) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , from above grade metering-regulating stations that are not above grade transmission-distribution transfer stations.
                            </P>
                            <P>
                                (B) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , from above grade metering regulating stations that are not above grade transmission-distribution transfer stations.
                            </P>
                            <P>(3) You must indicate whether your facility contains any emission source types in vacuum service as defined in § 98.238. If your facility contains equipment in vacuum service, you must report the information specified in paragraphs (r)(3)(i) through (iii) of this section separately for each emission source type in vacuum service that is located at your well-pad site, gathering and boosting site, or facility, as applicable.</P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) Emission source type.</P>
                            <P>(iii) Total number of the emission source type at the well-pad site, gathering and boosting site, or facility, as applicable.</P>
                            <P>
                                (s) 
                                <E T="03">Offshore petroleum and natural gas production.</E>
                                 You must report the information specified in paragraphs (s)(1) through (3) of this section for your facility.
                            </P>
                            <P>(1) The BOEM Facility ID(s) that correspond(s) to your facility, if applicable.</P>
                            <P>(2) If you adjusted emissions according to § 98.233(s)(1)(ii) or (s)(2)(ii), report the information specified in paragraphs (s)(2)(i) and (ii) of this section.</P>
                            <P>(i) Facility operating hours for the year of the most recent emissions calculated according to § 98.233(s)(1)(ii) or § 98.233(s)(2)(ii) prior to the current reporting year.</P>
                            <P>(ii) Facility operating hours for the current reporting year.</P>
                            <P>(3) For each emission source type listed in the most recent monitoring and calculation methods published by BOEM as referenced in 30 CFR 550.302 through 304, report the information specified in paragraphs (s)(3)(i) through (iii) of this section.</P>
                            <P>
                                (i) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                .
                            </P>
                            <P>
                                (ii) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                .
                            </P>
                            <P>
                                (iii) Annual N
                                <E T="52">2</E>
                                O emissions, in metric tons N
                                <E T="52">2</E>
                                O.
                            </P>
                            <P>(t) [Reserved]</P>
                            <P>(u) [Reserved]</P>
                            <P>(v) [Reserved]</P>
                            <P>
                                (w) 
                                <E T="03">EOR injection pumps.</E>
                                 You must indicate whether CO
                                <E T="52">2</E>
                                 EOR injection was used at your facility during the calendar year and if any EOR injection pump blowdowns occurred during the year. If any EOR injection pump blowdowns occurred during the calendar year, then you must report the information specified in paragraphs (w)(1) through (8) of this section for each EOR injection pump system.
                            </P>
                            <P>(1) Sub-basin ID.</P>
                            <P>(2) EOR injection pump system identifier.</P>
                            <P>(3) Pump capacity, in barrels per day.</P>
                            <P>(4) Total volume of EOR injection pump system equipment chambers, in cubic feet (“Vv” in equation W-37 to § 98.233).</P>
                            <P>(5) Number of blowdowns for the EOR injection pump system in the calendar year.</P>
                            <P>(6) Density of critical phase EOR injection gas, in kilograms per cubic foot (“Rc” in equation W-37 to § 98.233).</P>
                            <P>
                                (7) Mass fraction of CO
                                <E T="52">2</E>
                                 in critical phase EOR injection gas (“GHG
                                <E T="52">CO2</E>
                                ” in equation W-37 to § 98.233).
                            </P>
                            <P>
                                (8) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , from EOR injection pump system blowdowns.
                            </P>
                            <P>
                                (x) 
                                <E T="03">EOR hydrocarbon liquids.</E>
                                 You must indicate whether hydrocarbon liquids were produced through EOR operations. If hydrocarbon liquids were produced through EOR operations, you must report the information specified in paragraphs (x)(1) through (4) of this section for each sub-basin category with EOR operations.
                            </P>
                            <P>(1) Sub-basin ID.</P>
                            <P>
                                (2) Total volume of hydrocarbon liquids produced through EOR operations in the calendar year, in barrels (“V
                                <E T="52">hl</E>
                                ” in equation W-38 to § 98.233).
                            </P>
                            <P>
                                (3) Average CO
                                <E T="52">2</E>
                                 retained in hydrocarbon liquids downstream of the storage tank, in metric tons per barrel under standard conditions (“S
                                <E T="52">hl</E>
                                ” in equation W-38 to § 98.233).
                            </P>
                            <P>
                                (4) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , from CO
                                <E T="52">2</E>
                                 retained in hydrocarbon liquids produced through EOR operations downstream of the storage tank (“MassCO
                                <E T="52">2</E>
                                ” in equation W-38 to § 98.233).
                            </P>
                            <P>
                                (y) 
                                <E T="03">Other large release events.</E>
                                 You must indicate whether there were any other large release events from your facility during the reporting year and indicate whether your facility was notified of a potential super-emitter release under the provisions of § 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter. If there were any other large release events, you must report the total number of other large release events from your facility that occurred during the reporting year and, for each other large release event, report the information specified in paragraphs (y)(1) through (10) of this section. If you received a super-emitter release notification under the provisions of § 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter that the EPA has not determined to contain a demonstrable error according to the provisions in § 98.233(y)(6), you must include the emissions from that source or event within your subpart W report unless you can provide certification that the facility does not own or operate the equipment at the location identified in the notification using the methods specified in § 98.233(y)(6). Regardless, if you received a super-emitter release notification under the provisions of §§ 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you must also report the information specified in paragraph (y)(11) of this section.
                            </P>
                            <P>(1) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>
                                (2) Unique release event identification number (
                                <E T="03">e.g.</E>
                                , Event 1, Event 2).
                            </P>
                            <P>
                                (3) The latitude and longitude of the release in decimal degrees to at least 
                                <PRTPAGE P="42317"/>
                                four digits to the right of the decimal point.
                            </P>
                            <P>(4) The approximate start date, start time, and duration (in hours) of the release event, and an indication of how the start date and time were determined (determined based on pressure monitor, temperature monitor, other monitored process parameter (specify), assigned based on last monitoring or measurement survey showing no large release (specify monitoring or measurement survey method), or used the 91-day default start date).</P>
                            <P>(5) A general description of the event. Include:</P>
                            <P>(i) Identification of the equipment involved in the release.</P>
                            <P>(ii) A description of how the release occurred, from one of the following categories: maintenance event, fire/explosion, gas well blowout, oil well blowout, gas well release, oil well release, pressure relief, large leak, and other (specify).</P>
                            <P>(iii) An indication of whether the release exceeded a threshold in § 98.233(y)(1)(i) or in § 98.233(y)(1)(ii).</P>
                            <P>(iv) A description of the technology or method used to identify the release.</P>
                            <P>(v) An indication of whether the release was identified under the provisions of § 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter and, if the release was identified under the provisions of §§ 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, a unique notification ID number for the notification as assigned in paragraph (y)(11)(i) of this section.</P>
                            <P>(vi) An indication of whether a portion of the natural gas released was combusted during the release, and if so, the fraction of the natural gas released that was estimated to be combusted and the assumed combustion efficiency for the combusted natural gas.</P>
                            <P>(6) The total volume of gas released during the event in standard cubic feet.</P>
                            <P>
                                (7) The volume fraction of CO
                                <E T="52">2</E>
                                 in the gas released during the event.
                            </P>
                            <P>
                                (8) The volume fraction of CH
                                <E T="52">4</E>
                                 in the gas released during the event.
                            </P>
                            <P>
                                (9) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , from the release event that occurred during the reporting year.
                            </P>
                            <P>
                                (10) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , from the release event that occurred during the reporting year and the maximum CH
                                <E T="52">4</E>
                                 emissions rate, in kilograms per hour, determined for any period of the event according to the provisions § 98.233(y)(2)(i).
                            </P>
                            <P>(11) Report the total number of super-emitter release notifications received from the EPA under the provisions of §§ 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter for this facility for events that occurred during the reporting year that were not determined by the EPA to have a demonstratable error in the notification and, for each such super-emitter release notification, report the information specified in paragraphs (y)(11)(i) through (v) of this section.</P>
                            <P>(i) Unique notification identification number (e.g., Notification_01, Notification_02). If a unique notification number was provided with a notification received under the provisions of § 60.5371, 60.5371a, or 60.5371b of this chapter, an applicable approved state plan, or applicable Federal plan in part 62 of this chapter, report the number associated with the event provided in the notification.</P>
                            <P>(ii) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only) to which the notification was attributed.</P>
                            <P>(iii) Based on any assessment or investigation triggered by the notification, indicate if the emissions were from normal operations, a planned maintenance event, leaking equipment, malfunctioning equipment or device, or undetermined cause.</P>
                            <P>(iv) An indication of whether the emissions identified via the notification are included in annual emissions reported under this subpart and, if so, the source type under which the emissions identified via the notification are reported (from the list of source types required to be reported as specified in § 98.232 for the facility's applicable industry segment). If the emissions were reported following the requirements of § 98.233(y) as an other large release event, report the unique release event identification number assigned to the other large release event as reported in paragraph (y)(2) of this section. If the emissions identified via the notification are not included in the annual emissions reported under this subpart, you must provide certification that the facility does not own or operate the equipment at the location identified in the notification as specified in § 98.233(y)(6)(i) or provide certification that the facility conducted a complete investigation of the site as specified in § 98.233(y)(6)(ii) and does not own or operate the emitting equipment at the location identified in the notification.</P>
                            <P>(v) Provide an indication if you received a super-emitter release notification from the EPA after December 31 of the reporting year for which investigations are on-going such that the annual report that has been submitted may be revised and resubmitted pending the outcome of the super-emitter investigation.</P>
                            <P>
                                (z) 
                                <E T="03">Combustion equipment.</E>
                                 If your facility is required by § 98.232(c)(22), (i)(7), or (j)(12) to report emissions from combustion equipment, then you must indicate whether your facility has any combustion units subject to reporting according to paragraph (a)(1)(xx), (a)(8)(vi), or (a)(9)(xiii) of this section. If your facility contains any combustion units subject to reporting according to paragraph (a)(1)(xx), (a)(8)(vi), or (a)(9)(xiii) of this section, then you must report the information specified in paragraphs (z)(1) and (2) of this section, as applicable. You must report the information specified in paragraphs (z)(1) and (2) of this section, as applicable, for each well-pad site (for onshore petroleum and natural gas production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments).
                            </P>
                            <P>(1) Indicate whether the combustion units include: External fuel combustion units with a rated heat capacity less than or equal to 5 million Btu per hour; or, internal fuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 mmBtu/hr (or the equivalent of 130 horsepower). If the facility contains external fuel combustion units with a rated heat capacity less than or equal to 5 million Btu per hour or internal fuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 million Btu per hour (or the equivalent of 130 horsepower), then you must report the information specified in paragraphs (z)(1)(i) through (iii) of this section for each unit type.</P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) The type of combustion unit.</P>
                            <P>(iii) The total number of combustion units.</P>
                            <P>
                                (2) Indicate whether the combustion units include: External fuel combustion units with a rated heat capacity greater than 5 million Btu per hour; internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 
                                <PRTPAGE P="42318"/>
                                horsepower); or, internal fuel combustion units of any heat capacity that are compressor-drivers. For each type of combustion unit at your facility, you must report the information specified in paragraphs (z)(2)(i) through (iv) and (z)(2)(viii) through (x) of this section, except for internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower) or internal fuel combustion units of any heat capacity that are compressor-drivers that combust natural gas meeting the criteria in § 98.233(z), which must report the information specified in paragraphs (z)(2)(i) through (x) of this section. Information must be reported for each combustion unit type, fuel type, and method for determining the CH
                                <E T="52">4</E>
                                 emission factor combination, as applicable.
                            </P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) The type of combustion unit including external fuel combustion units with a rated heat capacity greater than 5 million Btu per hour; internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or internal fuel combustion units of any heat capacity that are compressor-drivers.</P>
                            <P>(iii) The type of fuel combusted.</P>
                            <P>(iv) The quantity of fuel combusted in the calendar year, in thousand standard cubic feet, gallons, or tons.</P>
                            <P>(v) The equipment type, including reciprocating 2-stroke-lean burn, reciprocating 4-stroke lean-burn, reciprocating 4-stroke rich-burn, and gas turbine.</P>
                            <P>(vi) The method used to determine the methane emission factor, including the default emission factor from table W-7 to this subpart, OEM data, or performance tests in § 98.234(i) for natural gas described in § 98.233(z)(1) or (2), or performance tests in § 98.234(i) or default combustion efficiency for fuels described in section § 98.233(z)(3).</P>
                            <P>
                                (vii) The value of the CH
                                <E T="52">4</E>
                                 emission factor (kg CH
                                <E T="52">4</E>
                                /mmBtu). If multiple performance tests were performed in the same reporting year, the arithmetic average value of CH
                                <E T="52">4</E>
                                 emission factor (kg CH
                                <E T="52">4</E>
                                /mmBtu). This information is not required if CH
                                <E T="52">4</E>
                                 emissions were calculated per § 98.233(z)(3)(ii)(D).
                            </P>
                            <P>
                                (viii) Annual CO
                                <E T="52">2</E>
                                 emissions, in metric tons CO
                                <E T="52">2</E>
                                , calculated according to § 98.233(z)(1) through (3).
                            </P>
                            <P>
                                (ix) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , calculated according to § 98.233(z)(1) through (3).
                            </P>
                            <P>
                                (x) Annual N
                                <E T="52">2</E>
                                O emissions, in metric tons N
                                <E T="52">2</E>
                                O, calculated according to § 98.233(z)(1) through (3).
                            </P>
                            <P>
                                (aa) 
                                <E T="03">Industry segment-specific information.</E>
                                 Each facility must report the information specified in paragraphs (aa)(1) through (11) of this section, for each applicable industry segment, determined using a flow meter that meets the requirements of § 98.234(b) for quantities that are sent to sale or through the facility and determined by using best available data for other quantities. If a quantity required to be reported is zero, you must report zero as the value.
                            </P>
                            <P>(1) For onshore petroleum and natural gas production, report the data specified in paragraphs (aa)(1)(i) and (iv) of this section.</P>
                            <P>(i) Report the information specified in paragraphs (aa)(1)(i)(A) through (C) of this section for the basin as a whole, unless otherwise specified.</P>
                            <P>(A) The quantity of gas produced in the calendar year from wells, in thousand standard cubic feet. This includes gas that is routed to a pipeline, vented or flared, or used in field operations. This does not include gas injected back into reservoirs or shrinkage resulting from lease condensate production.</P>
                            <P>(B) The quantity of natural gas produced from producing wells that is sent to sale in the calendar year, in thousand standard cubic feet.</P>
                            <P>(C) The quantity of crude oil and condensate produced from producing wells that is sent to sale in the calendar year, in barrels.</P>
                            <P>(ii) Report the information specified in paragraphs (aa)(1)(ii)(A) through (M) of this section for each unique sub-basin category.</P>
                            <P>(A) State.</P>
                            <P>(B) County.</P>
                            <P>(C) Formation type.</P>
                            <P>(D) The number of producing wells at the end of the calendar year (exclude only those wells permanently shut-in and plugged).</P>
                            <P>(E) The number of producing wells acquired during the calendar year.</P>
                            <P>(F) The number of producing wells divested during the calendar year.</P>
                            <P>(G) The number of wells completed during the calendar year.</P>
                            <P>(H) The number of wells permanently shut-in and plugged during the calendar year.</P>
                            <P>
                                (I) Average mole fraction of CH
                                <E T="52">4</E>
                                 in produced gas.
                            </P>
                            <P>
                                (J) Average mole fraction of CO
                                <E T="52">2</E>
                                 in produced gas.
                            </P>
                            <P>(K) If an oil sub-basin, report the average GOR of all wells, in thousand standard cubic feet per barrel.</P>
                            <P>(L) If an oil sub-basin, report the average API gravity of all wells.</P>
                            <P>(M) If an oil sub-basin, report average low pressure separator pressure, in pounds per square inch gauge.</P>
                            <P>(iii) Report the information specified in paragraphs (aa)(1)(iii)(A) through (D) of this section for each well located in the facility.</P>
                            <P>(A) Well ID number.</P>
                            <P>(B) Well-pad ID.</P>
                            <P>(C) For each well permanently shut-in and plugged during the calendar year, the quantity of natural gas produced that is sent to sale in the calendar year, in thousand standard cubic feet.</P>
                            <P>(D) For each well permanently shut-in and plugged during the calendar year, the quantity of crude oil and condensate produced that is sent to sale in the calendar year, in barrels.</P>
                            <P>(iv) Report the information specified in paragraphs (aa)(1)(iv)(A) through (C) of this section for each well-pad site located in the facility.</P>
                            <P>(A) A unique name or ID number for the well-pad.</P>
                            <P>(B) Sub-basin ID.</P>
                            <P>(C) The latitude and longitude of the well-pad representing the geographic centroid or center point of the well-pad in decimal degrees to at least four digits to the right of the decimal point.</P>
                            <P>(2) For offshore production, report the quantities specified in paragraphs (aa)(2)(i) through (iv) of this section.</P>
                            <P>(i) The quantity of natural gas produced from producing wells that is sent to sale in the calendar year, in thousand standard cubic feet.</P>
                            <P>(ii) The quantity of crude oil and condensate produced from producing wells that is sent to sale in the calendar year, in barrels.</P>
                            <P>(iii) For each well permanently shut-in and plugged during the calendar year, the quantity of natural gas produced that is sent to sale in the calendar year, in thousand standard cubic feet.</P>
                            <P>(iv) For each well permanently shut-in and plugged during the calendar year, the quantity of crude oil and condensate produced that is sent to sale in the calendar year, in barrels.</P>
                            <P>(3) For natural gas processing, if your facility fractionates NGLs and also reported as a supplier to subpart NN of this part, you must report the information specified in paragraphs (aa)(3)(ii) and (aa)(3)(v) through (ix) of this section. Otherwise, report the information specified in paragraphs (aa)(3)(i) through (ix) of this section.</P>
                            <P>
                                (i) The quantity of natural gas received at the gas processing plant for processing in the calendar year, in thousand standard cubic feet.
                                <PRTPAGE P="42319"/>
                            </P>
                            <P>(ii) The quantity of processed (residue) gas leaving the gas processing plant in the calendar year, in thousand standard cubic feet.</P>
                            <P>(iii) The cumulative quantity of all NGLs (bulk and fractionated) received at the gas processing plant in the calendar year, in barrels.</P>
                            <P>(iv) The cumulative quantity of all NGLs (bulk and fractionated) leaving the gas processing plant in the calendar year, in barrels.</P>
                            <P>
                                (v) Average mole fraction of CH
                                <E T="52">4</E>
                                 in natural gas received.
                            </P>
                            <P>
                                (vi) Average mole fraction of CO
                                <E T="52">2</E>
                                 in natural gas received.
                            </P>
                            <P>(vii) Indicate whether the facility fractionates NGLs.</P>
                            <P>(viii) Indicate whether the facility reported as a supplier to subpart NN of this part under the same e-GGRT identification number in the calendar year.</P>
                            <P>(ix) The quantity of residue gas leaving that has been processed by the facility and any gas that passes through the facility to sales without being processed by the facility.</P>
                            <P>(4) For natural gas transmission compression, report the quantity specified in paragraphs (aa)(4)(i) through (v) of this section.</P>
                            <P>(i) The quantity of natural gas transported through the compressor station in the calendar year, in thousand standard cubic feet.</P>
                            <P>(ii) Number of compressors.</P>
                            <P>(iii) Total compressor power rating of all compressors combined, in horsepower.</P>
                            <P>(iv) Average upstream pipeline pressure, in pounds per square inch gauge.</P>
                            <P>(v) Average downstream pipeline pressure, in pounds per square inch gauge.</P>
                            <P>(5) For underground natural gas storage, report the quantities specified in paragraphs (aa)(5)(i) through (iii) of this section.</P>
                            <P>(i) The quantity of gas injected into storage in the calendar year, in thousand standard cubic feet.</P>
                            <P>(ii) The quantity of natural gas withdrawn from storage and sent to sale in the calendar year, in thousand standard cubic feet.</P>
                            <P>(iii) Total storage capacity, in thousand standard cubic feet.</P>
                            <P>(6) For LNG import equipment, report the quantity of LNG imported that is sent to sale in the calendar year, in thousand standard cubic feet.</P>
                            <P>(7) For LNG export equipment, report the quantity of LNG exported that is sent to sale in the calendar year, in thousand standard cubic feet.</P>
                            <P>(8) For LNG storage, report the quantities specified in paragraphs (aa)(8)(i) through (iii) of this section.</P>
                            <P>(i) The quantity of LNG added into storage in the calendar year, in thousand standard cubic feet.</P>
                            <P>(ii) The quantity of LNG withdrawn from storage and sent to sale in the calendar year, in thousand standard cubic feet.</P>
                            <P>(iii) Total storage capacity, in thousand standard cubic feet.</P>
                            <P>(9) [Reserved]</P>
                            <P>(10) For onshore petroleum and natural gas gathering and boosting facilities, report the quantities specified in paragraphs (aa)(10)(i) through (v) of this section.</P>
                            <P>(i) The quantity of gas received by the gathering and boosting facility in the calendar year, in thousand standard cubic feet.</P>
                            <P>(ii) The quantity of natural gas transported from the gathering and boosting facility in the calendar year, in thousand standard cubic feet.</P>
                            <P>(iii) The quantity of all hydrocarbon liquids received by the gathering and boosting facility in the calendar year, in barrels.</P>
                            <P>(iv) The quantity of all hydrocarbon liquids transported from the gathering and boosting facility in the calendar year, in barrels.</P>
                            <P>(v) Report the information specified in paragraphs (aa)(10)(v)(A) through (E) of this section for each gathering and boosting site located in the facility for which there were emissions in the calendar year.</P>
                            <P>(A) A unique name or ID number for the gathering and boosting site.</P>
                            <P>(B) Gathering and boosting site type (gathering compressor station, centralized oil production site, gathering pipeline, or other fence-line site).</P>
                            <P>(C) State.</P>
                            <P>(D) For gathering compressor stations, centralized oil production sites, and other fence-line sites, county.</P>
                            <P>(E) For gathering compressor stations, centralized oil production sites, and other fence-line sites, the latitude and longitude of the gathering and boosting site representing the geographic centroid or center point of the site in decimal degrees to at least four digits to the right of the decimal point.</P>
                            <P>(11) For onshore natural gas transmission pipeline facilities, report the quantities specified in paragraphs (aa)(11)(i) through (vi) of this section.</P>
                            <P>(i) The quantity of natural gas received at all custody transfer stations in the calendar year, in thousand standard cubic feet. This value may include meter corrections, but only for the calendar year covered by the annual report.</P>
                            <P>(ii) The quantity of natural gas withdrawn from underground natural gas storage and LNG storage (regasification) facilities owned and operated by the onshore natural gas transmission pipeline owner or operator that are not subject to this subpart in the calendar year, in thousand standard cubic feet.</P>
                            <P>(iii) The quantity of natural gas added to underground natural gas storage and LNG storage (liquefied) facilities owned and operated by the onshore natural gas transmission pipeline owner or operator that are not subject to this subpart in the calendar year, in thousand standard cubic feet.</P>
                            <P>(iv) The quantity of natural gas transported through the facility and transferred to third parties such as LDCs or other transmission pipelines, in thousand standard cubic feet.</P>
                            <P>(v) The quantity of natural gas consumed by the transmission pipeline facility for operational purposes, in thousand standard cubic feet.</P>
                            <P>(vi) The miles of transmission pipeline for each state in the facility.</P>
                            <P>
                                (bb) 
                                <E T="03">Missing data.</E>
                                 For any missing data procedures used, report the information in § 98.3(c)(8) and the procedures used to substitute an unavailable value of a parameter, except as provided in paragraphs (bb)(1) and (2) of this section.
                            </P>
                            <P>(1) For quarterly measurements, report the total number of quarters that a missing data procedure was used for each data element rather than the total number of hours.</P>
                            <P>(2) For annual or biannual (once every two years) measurements, you do not need to report the number of hours that a missing data procedure was used for each data element.</P>
                            <P>
                                (cc) 
                                <E T="03">Delay in reporting for wildcat wells and delineation wells.</E>
                                 If you elect to delay reporting the information in paragraph (g)(5)(i) or (ii), (g)(5)(iii)(A) or (B), (h)(1)(iv), (h)(2)(iv), (j)(1)(iii), (j)(2)(i)(A), (l)(1)(v), (l)(2)(v), (l)(3)(iv), (l)(4)(iv), (m)(5) or (6), (dd)(1)(iii), (dd)(1)(vi)(A), (B), or (C), (dd)(3)(iii)(A), or (dd)(3)(iii)(D)(
                                <E T="03">1</E>
                                ), (
                                <E T="03">2</E>
                                ), or (
                                <E T="03">3</E>
                                ) of this section, you must report the information required in that paragraph no later than the date 2 years following the date specified in § 98.3(b) introductory text.
                            </P>
                            <P>
                                (dd) 
                                <E T="03">Drilling mud degassing.</E>
                                 You must indicate whether there were mud degassing operations at your facility, and if so, which methods (as specified in § 98.233(dd)) were used to calculate emissions. For wells for which your facility performed mud degassing operations and used Calculation Method 1, then you must report the information specified in paragraph (dd)(1) of this section. For wells for which your facility performed mud degassing operations and used Calculation Method 
                                <PRTPAGE P="42320"/>
                                2, then you must report the information specified in paragraph (dd)(2) of this section. For wells for which your facility performed mud degassing operations and used Calculation Method 3, then you must report the information specified in paragraph (dd)(3) of this section.
                            </P>
                            <P>(1) For each well for which you used Calculation Method 1 to calculate natural gas emissions from mud degassing, report the information specified in paragraphs (dd)(1)(i) through (viii) of this section.</P>
                            <P>(i) Well ID number.</P>
                            <P>(ii) Approximate total depth below surface, in feet.</P>
                            <P>(iii) Target hydrocarbon-bearing stratigraphic formation to which the well is drilled.</P>
                            <P>
                                (iv) Total time that drilling mud is circulated in the well (T
                                <E T="52">r</E>
                                 in equation W-41 to § 98.233 and T
                                <E T="52">p</E>
                                 in equation W-43 to § 98.233), in minutes, beginning with initial penetration of the first hydrocarbon-bearing zone until drilling mud ceases to be circulated in the wellbore. You may delay reporting of this data element for a representative well if you indicate in the annual report that one or more wells to which the calculated CH
                                <E T="52">4</E>
                                 emissions rate for the representative well (ER
                                <E T="52">s,CH4,r</E>
                                 in equation W-42 to § 98.233) is applied is a wildcat well or delineation well. You may delay reporting of this data element for any well if you indicate in the annual report that the well is a wildcat or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the total time that drilling mud is circulated in the well, in minutes.
                            </P>
                            <P>(v) The composition of the drilling mud: water-based, oil-based, or synthetic.</P>
                            <P>
                                (vi) If the well is not a representative well, Well ID number of the representative well used to derive the CH
                                <E T="52">4</E>
                                 emission rate used to calculate CH
                                <E T="52">4</E>
                                 emissions for this well.
                            </P>
                            <P>(vii) If the well is a representative well, report the information specified in paragraphs (dd)(1)(vi)(A) through (D) of this section.</P>
                            <P>
                                (A) Average mud rate (MR
                                <E T="52">r</E>
                                 in equation W-41 to § 98.233), in gallons per minute. You may delay reporting of this data element if you indicate in the annual report that one or more wells to which the calculated CH
                                <E T="52">4</E>
                                 emissions rate for the representative well (ER
                                <E T="52">s,CH4,r</E>
                                 in equation W-42 to § 98.233) is applied is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the average mud rate, in gallons per minute.
                            </P>
                            <P>
                                (B) Average concentration of natural gas in the drilling mud (X
                                <E T="52">n</E>
                                 in equation W-41 to § 98.233), in parts per million. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the average concentration of natural gas in the drilling mud in parts per million.
                            </P>
                            <P>
                                (C) Measured mole fraction for CH
                                <E T="52">4</E>
                                 in natural gas entrained in the drilling mud (GHG
                                <E T="52">CH4</E>
                                 in equation W-41 to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured mole fraction for CH
                                <E T="52">4</E>
                                 in natural gas entrained in the drilling mud.
                            </P>
                            <P>
                                (D) Calculated CH
                                <E T="52">4</E>
                                 emissions rate in standard cubic feet per minute (ER
                                <E T="52">s,CH4,r</E>
                                 in equation W-42 to § 98.233). You may delay reporting of this data element if you indicate in the annual report that that one or more wells to which  the calculated CH
                                <E T="52">4</E>
                                 emissions rate for the representative well (ER
                                <E T="52">s,CH4,r</E>
                                 in equation W-42 to § 98.233) is applied is a wildcat or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the calculated CH
                                <E T="52">4</E>
                                 emissions rate in standard cubic feet per minute.
                            </P>
                            <P>
                                (viii) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , from well drilling mud degassing, calculated according to § 98.233(dd)(1).
                            </P>
                            <P>(2) For each well for which you used Calculation Method 2 to calculate natural gas emissions from mud degassing, report the information specified in paragraphs (dd)(2)(i) through (iv) of this section.</P>
                            <P>(i) Well ID number.</P>
                            <P>
                                (ii) Total number of drilling days (DD
                                <E T="52">p</E>
                                 in equation W-44 to § 98.233).
                            </P>
                            <P>(iii) The composition of the drilling mud: water-based, oil-based, or synthetic.</P>
                            <P>
                                (iv) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , from drilling mud degassing, calculated according to § 98.233(dd)(2).
                            </P>
                            <P>(3) For each well for which you used Calculation Method 3 to calculate natural gas emissions from mud degassing, report the information specified in paragraphs (dd)(3)(i) through (iv) of this section.</P>
                            <P>(i) Well ID number.</P>
                            <P>(ii) For the time periods you used Calculation Method 1 to calculate natural gas emissions from mud degassing, report the information specified in paragraphs (dd)(3)(ii)(A) through (G) of this section.</P>
                            <P>(A) Approximate total depth below surface, in feet.</P>
                            <P>(B) Target hydrocarbon-bearing stratigraphic formation to which the well is drilled.</P>
                            <P>
                                (C) Total time that drilling mud is circulated in the well (T
                                <E T="52">r</E>
                                 in equation W-41 to § 98.233 and T
                                <E T="52">p</E>
                                 in equation W-43 to § 98.233), in minutes, beginning with initial penetration of the first hydrocarbon-bearing zone until drilling mud ceases to be circulated in the wellbore. You may delay reporting of this data element for a representative well if you indicate in the annual report that that one or more wells to which the calculated CH
                                <E T="52">4</E>
                                 emissions rate for the representative well (ER
                                <E T="52">s,CH4,r</E>
                                 in equation W-42 to § 98.233) is applied is a wildcat well or delineation well. You may delay reporting of this data element for any well if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the total time that drilling mud is circulated in the well, in minutes.
                            </P>
                            <P>(D) The composition of the drilling mud: water-based, oil-based, or synthetic.</P>
                            <P>
                                (E) If the well is not a representative well, Well ID number of the representative well used to derive the CH
                                <E T="52">4</E>
                                 emission rate used to calculate CH
                                <E T="52">4</E>
                                 emissions for this well.
                            </P>
                            <P>
                                (F) If the well is a representative well, report the information specified in paragraphs (dd)(3)(ii)(F)(
                                <E T="03">1</E>
                                ) through (
                                <E T="03">4</E>
                                ) of this section.
                            </P>
                            <P>
                                (
                                <E T="03">1</E>
                                ) Average mud rate (MR
                                <E T="52">r</E>
                                 in equation W-41 to § 98.233), in gallons per minute. You may delay reporting of this data element if you indicate in the annual report that one or more wells to which the calculated CH
                                <E T="52">4</E>
                                 emissions rate for the representative well (ER
                                <E T="52">s,CH4,r</E>
                                 in equation W-42 to § 98.233) is applied is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the average mud rate, in gallons per minute.
                            </P>
                            <P>
                                (
                                <E T="03">2</E>
                                ) Average concentration of natural gas in the drilling mud (X
                                <E T="52">n</E>
                                 in equation W-41 to § 98.233), in parts per million. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must 
                                <PRTPAGE P="42321"/>
                                report by the date specified in paragraph (cc) of this section the average concentration of natural gas in the drilling mud in parts per million.
                            </P>
                            <P>
                                (
                                <E T="03">3</E>
                                ) Measured mole fraction for CH
                                <E T="52">4</E>
                                 in natural gas entrained in the drilling mud (GHG
                                <E T="52">CH4</E>
                                 in equation W-41 to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured mole fraction for CH
                                <E T="52">4</E>
                                 in natural gas entrained in the drilling mud.
                            </P>
                            <P>
                                (
                                <E T="03">4</E>
                                ) Calculated CH
                                <E T="52">4</E>
                                 emissions rate in standard cubic feet per minute (ER
                                <E T="52">s,CH4,r</E>
                                 in equation W-42 to § 98.233). You may delay reporting of this data element if you indicate in the annual report that one or more wells to which the calculated CH
                                <E T="52">4</E>
                                 emissions rate for the representative well (ER
                                <E T="52">s,CH4,r</E>
                                 in equation W-42 to § 98.233) is applied is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the calculated CH
                                <E T="52">4</E>
                                 emissions rate in standard cubic feet per minute.
                            </P>
                            <P>
                                (G) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , from well drilling mud degassing, calculated according to § 98.233(dd)(1).
                            </P>
                            <P>(iii) For the time periods for each well for which you used Calculation Method 2 to calculate natural gas emissions from mud degassing, report the information specified in paragraphs (dd)(3)(iii)(A) through (C) of this section.</P>
                            <P>
                                (A) Total number of drilling days (DD
                                <E T="52">p</E>
                                 in equation W-44 to § 98.233).
                            </P>
                            <P>(B) The composition of the drilling mud: water-based, oil-based, or synthetic.</P>
                            <P>
                                (C) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , from drilling mud degassing, calculated according to § 98.233(dd)(2).
                            </P>
                            <P>
                                (iv) Total annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , from drilling mud degassing, calculated from summing the annual CH
                                <E T="52">4</E>
                                 emissions calculated from § 98.233(dd)(3)(iii)(E) and § 98.233(dd)(3)(iv)(C).
                            </P>
                            <P>
                                (ee) 
                                <E T="03">Crankcase vents.</E>
                                 You must indicate whether your facility performs any crankcase venting from reciprocating internal combustion engines. For all reciprocating internal combustion engines with crankcase vents, you must report the information specified in paragraph (ee)(1) of this section for each well-pad site (for onshore petroleum and natural gas production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments). For each reciprocating internal combustion engine that you conduct measurements as specified in § 98.233(ee)(1), you must report the information specified in paragraph (ee)(2) of this section. For reciprocating internal combustion engines with CH
                                <E T="52">4</E>
                                 emissions calculated as specified in § 98.233(ee)(2), you must report the information specified in paragraph (ee)(3) of this section for each well-pad site (for onshore petroleum and natural gas production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments).
                            </P>
                            <P>(1) The information and number of reciprocating internal combustion engines with crankcase vents as specified in paragraphs (ee)(1)(i) through (v) of this section, as applicable. If a reciprocating internal combustion engine with crankcase vents was vented directly to the atmosphere for part of the year and routed to a flare during another part of the year, then include the engine in each of the applicable counts specified in paragraphs (ee)(1)(iii) and (iv) of this section.</P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) The total number of reciprocating internal combustion engines with crankcase vents.</P>
                            <P>(iii) The total number of reciprocating internal combustion engines with crankcase vents that operated and were vented directly to the atmosphere.</P>
                            <P>(iv) The total number of reciprocating internal combustion engines with crankcase vents that operated and were routed to a flare.</P>
                            <P>(v) The total number of reciprocating internal combustion engines with crankcase vents that were in a manifolded group containing a compressor vent source with emissions reported under paragraph (o) or (p) of this section.</P>
                            <P>(2) Reciprocating internal combustion engines with crankcase vents that calculate emissions according to § 98.233(ee)(1) must report the information specified in paragraphs (ee)(2)(i) and (ii) of this section, as applicable.</P>
                            <P>(i) For each measurement performed on a crankcase vent, report the information specified in paragraphs (ee)(2)(i)(A) through (F) of this section.</P>
                            <P>(A) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(B) Unique name or ID for the reciprocating internal combustion engine.</P>
                            <P>(C) Measurement date.</P>
                            <P>(D) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions.</P>
                            <P>(E) Measured flow rate, in standard cubic feet per hour.</P>
                            <P>(F) If the measurement is for a manifolded group of crankcase vent sources, indicate the number of reciprocating internal compressor engines that were operating during measurement.</P>
                            <P>
                                (ii) Annual CH
                                <E T="52">4</E>
                                 emissions from the reciprocating internal combustion engine crankcase vent, in metric tons CH
                                <E T="52">4</E>
                                .
                            </P>
                            <P>(3) Reciprocating internal combustion engines with crankcase vents that calculate emissions according to § 98.233(ee)(2) must report the information specified in paragraphs (ee)(3)(i) through (iv) of this section.</P>
                            <P>(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).</P>
                            <P>(ii) Total number of reciprocating internal combustion engines with crankcase vents that were operational at some point in the calendar year at the well-pad site, gathering and boosting site, or facility, as applicable.</P>
                            <P>(iii) Total time that the reciprocating internal combustion engines with crankcase venting were operational in the calendar year, in hours (“T” in equation W-46 to § 98.233).</P>
                            <P>
                                (iv) Annual CH
                                <E T="52">4</E>
                                 emissions, in metric tons CH
                                <E T="52">4</E>
                                , calculated according to § 98.233(ee)(2).
                            </P>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>18. Amend § 98.237 by adding paragraph (g) to read as follows:</AMDPAR>
                        <SECTION>
                            <SECTNO>§ 98.237</SECTNO>
                            <SUBJECT>Records that must be retained.</SUBJECT>
                            <STARS/>
                            <P>(g) For each situation when you fail to fully conform with all cited provisions in either § 98.233(n)(1)(i) or (ii) for a period of 15 consecutive days and you utilized the Tier 3 default destruction and combustion efficiency values, you must document these periods when the non-conformance began, and the date when full conformance was re-established.</P>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>
                            19. Effective July 15, 2024, amend § 98.238 by adding definitions 
                            <PRTPAGE P="42322"/>
                            “Centralized oil production site,” “Gathering and boosting site,” “Gathering compressor station,” “Gathering pipeline site,” and “Well-pad site” in alphabetical order to read as follows:
                        </AMDPAR>
                        <SECTION>
                            <SECTNO>§ 98.238</SECTNO>
                            <SUBJECT>Definitions.</SUBJECT>
                            <STARS/>
                            <P>
                                <E T="03">Centralized oil production site</E>
                                 means any permanent combination of one or more hydrocarbon liquids storage tanks located on one or more contiguous or adjacent properties that does not also contain a permanent combination of one or more compressors that are part of the onshore petroleum and natural gas gathering and boosting facility that gathers hydrocarbon liquids from multiple well-pads. A 
                                <E T="03">centralized oil production site</E>
                                 is a type of gathering and boosting site for purposes of this subpart.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Gathering and boosting site</E>
                                 means a single gathering compressor station as defined in this section, centralized oil production site as defined in this section, gathering pipeline site as defined in this section, or other fence-line site within the onshore petroleum and natural gas gathering and boosting industry segment.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Gathering compressor station</E>
                                 means any permanent combination of one or more compressors located on one or more contiguous or adjacent properties that are part of the onshore petroleum and natural gas gathering and boosting facility that move natural gas at increased pressure through gathering pipelines or into or out of storage. A 
                                <E T="03">gathering compressor station</E>
                                 is a type of gathering and boosting site for purposes of this subpart.
                            </P>
                            <P>
                                <E T="03">Gathering pipeline site</E>
                                 means all of the gathering pipelines within a single state. A 
                                <E T="03">gathering pipeline site</E>
                                 is a type of gathering and boosting site for purposes of this subpart.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Well-pad site</E>
                                 means all equipment on or associated with a single well-pad. Specifically, the well-pad site includes all equipment on a single well-pad plus all equipment associated with that single well-pad.
                            </P>
                            <STARS/>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>20. Amend § 98.238 by:</AMDPAR>
                        <AMDPAR>a. Removing the definition “Acid gas removal vent emissions” a;</AMDPAR>
                        <AMDPAR>b. Adding definitions “Acid gas removal unit (AGR) vent emissions,” “Atmospheric pressure storage tank,” and “Automated liquids unloading” in alphabetical order;</AMDPAR>
                        <AMDPAR>c. Revising the definitions “Compressor mode” and “Compressor source;”</AMDPAR>
                        <AMDPAR>d. Adding definitions “Crankcase venting,” “Drilling mud,” “Drilling mud degassing,” “Enclosed combustion device,” and “Equivalent stratigraphic interval” in alphabetical order;</AMDPAR>
                        <AMDPAR>e. Removing the second definition “Facility with respect to natural gas distribution for purposes of reporting under this subpart and for the corresponding subpart A requirements”;</AMDPAR>
                        <AMDPAR>f. Revising the definitions “Flare stack emissions” and “Forced extraction of natural gas liquids”;</AMDPAR>
                        <AMDPAR>g. Revising the definitions “Gathering and boosting system” and “Gathering and boosting system owner or operator”; and</AMDPAR>
                        <AMDPAR>h. Adding definitions “In vacuum service,” “Manual liquids unloading,” “Mud rate,” “Nitrogen removal unit (NRU),” “Nitrogen removal unit vent emissions,” “Other large release event,” “Produced water,” “Routed to combustion,” “Target hydrocarbon-bearing stratigraphic formation,” “Transmission company interconnect M&amp;R station,” “Well blowout,” and “Well release” in alphabetical order.</AMDPAR>
                        <P>The additions and revisions read as follows:</P>
                        <SECTION>
                            <SECTNO>§ 98.238</SECTNO>
                            <SUBJECT>Definitions.</SUBJECT>
                            <STARS/>
                            <P>
                                <E T="03">Acid gas removal unit (AGR) vent emissions</E>
                                 mean the acid gas separated from the acid gas absorbing medium (
                                <E T="03">e.g.</E>
                                , an amine solution) and released with methane and other light hydrocarbons to the atmosphere.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Atmospheric pressure storage tank</E>
                                 means a vessel (excluding sumps) operating at atmospheric pressure that is designed to contain an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water and that is constructed entirely of non-earthen materials (
                                <E T="03">e.g.</E>
                                , wood, concrete, steel, plastic) that provide structural support. Atmospheric pressure storage tanks include both fixed roof tanks and floating roof tanks. Floating roof tanks include tanks with either an internal floating roof or an external floating roof.
                            </P>
                            <P>
                                <E T="03">Automated liquids unloading</E>
                                 means an unloading that is performed without manual interference. Examples of automated liquids unloadings include a timing and/or pressure device used to optimize intermittent shut-in of the well before liquids choke off gas flow or to open and close valves, continually operating equipment that does not require presence of an operator such as rod pumping units, automated and unmanned plunger lifts, or other unloading activities that do not entail a physical presence at the well-pad,
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Compressor mode</E>
                                 means the operational and pressurized status of a compressor. For both centrifugal compressors and reciprocating compressors, “mode” refers to either: Operating-mode, standby-pressurized-mode, or not-operating-depressurized-mode.
                            </P>
                            <P>
                                <E T="03">Compressor source</E>
                                 means the source of certain venting or leaking emissions from a centrifugal or reciprocating compressor. For centrifugal compressors, “source” refers to blowdown valve leakage through the blowdown vent, unit isolation valve leakage through an open blowdown vent without blind flanges, wet seal oil degassing vents, and dry seal vents. For reciprocating compressors, “source” refers to blowdown valve leakage through the blowdown vent, unit isolation valve leakage through an open blowdown vent without blind flanges, and rod packing emissions.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Crankcase venting</E>
                                 means the process of venting or removing blow-by from the void spaces of an internal combustion engine outside of the combustion cylinders to prevent excessive pressure build-up within the engine. This does not include ingestive systems that vent blow-by into the engine where it is returned to the combustion process (
                                <E T="03">e.g.</E>
                                , closed crankcase ventilation system, closed breather system) or if the vent blow-by is routed to another closed vent system.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Drilling mud</E>
                                 means a mixture of clays and additives with water, oil, or synthetic materials. While drilling, the drilling mud is continuously pumped through the drill string and out the bit to cool and lubricate the drill bit, and move cuttings through the wellbore to the surface.
                            </P>
                            <P>
                                <E T="03">Drilling mud degassing</E>
                                 means the practice of safely removing pockets of free gas entrained in the drilling mud once it is outside of the wellbore.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Enclosed combustion device</E>
                                 means a flare that uses a closed flame.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Equivalent stratigraphic interval</E>
                                 means the depth of the same stratum of rock in the Earth's subsurface.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Flare stack emissions</E>
                                 means CO
                                <E T="52">2</E>
                                 in gas routed to a flare, CO
                                <E T="52">2</E>
                                 from partial combustion of hydrocarbons in gas routed to a flare, CH
                                <E T="52">4</E>
                                 emissions resulting from the incomplete 
                                <PRTPAGE P="42323"/>
                                combustion of hydrocarbons in gas routed to a flare, and N
                                <E T="52">2</E>
                                O resulting from operation of a flare.
                            </P>
                            <P>
                                <E T="03">Forced extraction of natural gas liquids</E>
                                 means removal of ethane or higher carbon number hydrocarbons existing in the vapor phase in natural gas, by removing ethane or heavier hydrocarbons derived from natural gas into natural gas liquids by means of a forced extraction process. Forced extraction processes include but are not limited to refrigeration, absorption (lean oil), cryogenic expander, and combinations of these processes. Forced extraction does not include in and of itself natural gas dehydration, the collection or gravity separation of water or hydrocarbon liquids from natural gas at ambient temperature or heated above ambient temperatures, the condensation of water or hydrocarbon liquids through passive reduction in pressure or temperature, a Joule-Thomson valve, a dew point depression valve, or an isolated or standalone Joule-Thomson skid.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Gathering and boosting system</E>
                                 means a single network of pipelines, compressors and process equipment, including equipment to perform natural gas compression, dehydration, and acid gas removal, that has one or more connection points to gas and oil production or one or more other gathering and boosting systems and a downstream endpoint, typically a gas processing plant, transmission pipeline, LDC pipeline, or other gathering and boosting system.
                            </P>
                            <P>
                                <E T="03">Gathering and boosting system owner or operator</E>
                                 means any person that holds a contract in which they agree to transport petroleum or natural gas from one or more onshore petroleum and natural gas production wells or one or more other gathering and boosting systems to a downstream endpoint, typically a natural gas processing facility, another gathering and boosting system, a natural gas transmission pipeline, or a distribution pipeline, or any person responsible for custody of the petroleum or natural gas transported.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">In vacuum service</E>
                                 means equipment operating at an internal pressure which is at least 5 kilopascals (kPa) (0.7 psia) below ambient pressure.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Manual liquids unloading</E>
                                 means an unloading when field personnel attend to the well at the well-pad, for example to manually plunge a well at the site using a rig or other method, to open a valve to direct flow to an atmospheric tank to clear the well, or to manually shut-in the well to allow pressure to build in the well-bore. Manual unloadings may be performed on a routine schedule or on “as needed” basis.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Mud rate</E>
                                 means the pumping rate of the mud by the mud pumps, usually measured in gallons per minute (gpm).
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Nitrogen removal unit</E>
                                 (NRU) means a process unit that separates nitrogen from natural gas using various separation processes (
                                <E T="03">e.g.</E>
                                , cryogenic units, membrane units).
                            </P>
                            <P>
                                <E T="03">Nitrogen removal unit vent emissions</E>
                                 means the nitrogen gas separated from the natural gas and released with methane and other gases to the atmosphere.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Other large release event</E>
                                 means any planned or unplanned uncontrolled release to the atmosphere of gas, liquids, or mixture thereof, from wells and/or other equipment that result in emissions for which there are no methodologies in § 98.233 other than under § 98.233(y) to appropriately estimate these emissions. 
                                <E T="03">Other large release events</E>
                                 include, but are not limited to, well blowouts, well releases, pressure relief valve releases from process equipment other than hydrocarbon liquids storage tanks, storage tank cleaning and other maintenance activities, and releases that occur as a result of an accident, equipment rupture, fire, or explosion. 
                                <E T="03">Other large release events</E>
                                 also include failure of equipment or equipment components such that a single equipment leak or release has emissions that exceed the emissions calculated for that source using applicable methods in § 98.233(a) through (h), (j) through (s), (w), (x), (dd), or (ee) by the threshold in § 98.233(y)(1)(ii). 
                                <E T="03">Other large release events</E>
                                 do not include blowdowns for which emissions are calculated according to the provisions in § 98.233(i).
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Produced water</E>
                                 means the water (brine) brought up from the hydrocarbon-bearing strata during the extraction of oil and gas, and can include formation water, injection water, and any chemicals added downhole or during the oil/water separation process.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Routed to combustion</E>
                                 means, for onshore petroleum and natural gas production facilities, natural gas distribution facilities, and onshore petroleum and natural gas gathering and boosting facilities, that emissions are routed to stationary or portable fuel combustion equipment specified in § 98.232(c)(22), (i)(7), or (j)(12), as applicable. For all other industry segments in this subpart, 
                                <E T="03">routed to combustion</E>
                                 means that emissions are routed to a stationary fuel combustion unit subject to subpart C of this part (General Stationary Fuel Combustion Sources).
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Target hydrocarbon-bearing stratigraphic formation</E>
                                 means the stratigraphic interval intended to be the primary hydrocarbon producing formation.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Transmission company interconnect M&amp;R station</E>
                                 means a metering and pressure regulating stations with an inlet pressure above 100 psig located at a point of transmission pipeline to transmission pipeline interconnect.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Well blowout</E>
                                 means a complete loss of well control for a long duration of time resulting in an emissions release.
                            </P>
                            <STARS/>
                            <P>
                                <E T="03">Well release</E>
                                 means a short duration of uncontrolled emissions release from a well followed by a period of controlled emissions release in which control techniques were successfully implemented.
                            </P>
                            <STARS/>
                        </SECTION>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>
                            21. Remove tables W-1A, W-1B, W-1C, W-1D, and W-1E to subpart W of part 98 and add table W-1 to subpart W of part 98 in numerical order to read as follows:
                            <PRTPAGE P="42324"/>
                        </AMDPAR>
                        <GPOTABLE COLS="3" OPTS="L2,nj,i1" CDEF="s100,r100,15">
                            <TTITLE>Table W-1 to Subpart W of Part 98—Default Whole Gas Population Emission Factors</TTITLE>
                            <BOXHD>
                                <CHED H="1">Industry segment</CHED>
                                <CHED H="1">Source type/component</CHED>
                                <CHED H="1">
                                    Emission factor
                                    <LI>(scf whole gas/</LI>
                                    <LI>hour/unit)</LI>
                                </CHED>
                            </BOXHD>
                            <ROW EXPSTB="02" RUL="s">
                                <ENT I="21">
                                    <E T="02">Population Emission Factors—Pneumatic Device Vents and Pneumatic Pumps, Gas Service</E>
                                     
                                    <SU>1</SU>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">• Onshore petroleum and natural gas production</ENT>
                                <ENT>
                                    Continuous Low Bleed Pneumatic Device Vents 
                                    <SU>2</SU>
                                </ENT>
                                <ENT>6.8</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">• Onshore petroleum and natural gas gathering and boosting</ENT>
                                <ENT>
                                    Continuous High Bleed Pneumatic Device Vents 
                                    <SU>2</SU>
                                </ENT>
                                <ENT>21</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>
                                    Intermittent Bleed Pneumatic Device Vents 
                                    <SU>2</SU>
                                </ENT>
                                <ENT>8.8</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>
                                    Pneumatic Pumps 
                                    <SU>3</SU>
                                </ENT>
                                <ENT>13.3</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">• Onshore natural gas processing</ENT>
                                <ENT>
                                    Continuous Low Bleed Pneumatic Device Vents 
                                    <SU>2</SU>
                                </ENT>
                                <ENT>6.8</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">• Onshore natural gas transmission compression</ENT>
                                <ENT>
                                    Continuous High Bleed Pneumatic Device Vents 
                                    <SU>2</SU>
                                </ENT>
                                <ENT>30</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">• Underground natural gas storage</ENT>
                                <ENT>
                                    Intermittent Bleed Pneumatic Device Vents 
                                    <SU>2</SU>
                                </ENT>
                                <ENT>2.3</ENT>
                            </ROW>
                            <ROW RUL="s">
                                <ENT I="01">• Natural gas distribution</ENT>
                                <ENT O="xl"/>
                                <ENT O="xl"/>
                            </ROW>
                            <ROW EXPSTB="02" RUL="s">
                                <ENT I="21">
                                    <E T="02">Population Emission Factors—Major Equipment, Gas Service</E>
                                     
                                    <SU>1</SU>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">• Onshore petroleum and natural gas production</ENT>
                                <ENT>Wellhead</ENT>
                                <ENT>8.87</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">• Onshore petroleum and natural gas gathering and boosting</ENT>
                                <ENT>Separator</ENT>
                                <ENT>9.65</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Meters/Piping</ENT>
                                <ENT>7.04</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Compressor</ENT>
                                <ENT>13.8</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Dehydrator</ENT>
                                <ENT>8.09</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Heater</ENT>
                                <ENT>5.22</ENT>
                            </ROW>
                            <ROW RUL="s">
                                <ENT I="22"> </ENT>
                                <ENT>Storage Vessel</ENT>
                                <ENT>1.83</ENT>
                            </ROW>
                            <ROW EXPSTB="02" RUL="s">
                                <ENT I="21">
                                    <E T="02">Population Emission Factors—Major Equipment, Crude Service</E>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">Onshore petroleum and natural gas production</ENT>
                                <ENT>Wellhead</ENT>
                                <ENT>4.13</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Separator</ENT>
                                <ENT>4.77</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Meters/Piping</ENT>
                                <ENT>12.4</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Compressor</ENT>
                                <ENT>13.8</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Dehydrator</ENT>
                                <ENT>8.09</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Heater</ENT>
                                <ENT>3.2</ENT>
                            </ROW>
                            <ROW RUL="s">
                                <ENT I="22"> </ENT>
                                <ENT>Storage Vessel</ENT>
                                <ENT>1.91</ENT>
                            </ROW>
                            <ROW EXPSTB="02" RUL="s">
                                <ENT I="21">
                                    <E T="02">Population Emission Factors—Gathering Pipelines, by Material Type</E>
                                     
                                    <SU>4</SU>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">Onshore petroleum and natural gas gathering and boosting</ENT>
                                <ENT>Protected Steel</ENT>
                                <ENT>0.93</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Unprotected Steel</ENT>
                                <ENT>8.2</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Plastic/Composite</ENT>
                                <ENT>0.28</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Cast Iron</ENT>
                                <ENT>8.4</ENT>
                            </ROW>
                            <TNOTE>
                                <SU>1</SU>
                                 For multi-phase flow that includes gas, use the gas service emission factors.
                            </TNOTE>
                            <TNOTE>
                                <SU>2</SU>
                                 Emission factor is in units of “scf whole gas/hour/device.”
                            </TNOTE>
                            <TNOTE>
                                <SU>3</SU>
                                 Emission factor is in units of “scf whole gas/hour/pump.”
                            </TNOTE>
                            <TNOTE>
                                <SU>4</SU>
                                 Emission factors are in units of “scf whole gas/hour/mile of pipeline.”
                            </TNOTE>
                        </GPOTABLE>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>22. Revise table W-2 to subpart W of part 98 to read as follows:</AMDPAR>
                        <GPOTABLE COLS="4" OPTS="L2,i1" CDEF="s50,20,20,20">
                            <TTITLE>Table W-2 to Subpart W of Part 98—Default Whole Gas Leaker Emission Factors</TTITLE>
                            <BOXHD>
                                <CHED H="1">Equipment components</CHED>
                                <CHED H="1">Emission factor (scf whole gas/hour/component)</CHED>
                                <CHED H="2">If you survey using Method 21 as specified in § 98.234(a)(2)(i)</CHED>
                                <CHED H="2">If you survey using Method 21 as specified in § 98.234(a)(2)(ii)</CHED>
                                <CHED H="2">If you survey using any of the methods in § 98.234(a)(1), (3), or (5)</CHED>
                            </BOXHD>
                            <ROW EXPSTB="03" RUL="s">
                                <ENT I="21">
                                    <E T="02">Leaker Emission Factors—Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting—All Components, Gas Service</E>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">Valve</ENT>
                                <ENT>9.6</ENT>
                                <ENT>5.5</ENT>
                                <ENT>16</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Flange</ENT>
                                <ENT>6.9</ENT>
                                <ENT>4.0</ENT>
                                <ENT>11</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Connector (other)</ENT>
                                <ENT>4.9</ENT>
                                <ENT>2.8</ENT>
                                <ENT>7.9</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">
                                    Open-Ended Line 
                                    <SU>1</SU>
                                </ENT>
                                <ENT>6.3</ENT>
                                <ENT>3.6</ENT>
                                <ENT>10</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Pressure Relief Valve</ENT>
                                <ENT>7.8</ENT>
                                <ENT>4.5</ENT>
                                <ENT>13</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Pump Seal</ENT>
                                <ENT>14</ENT>
                                <ENT>8.3</ENT>
                                <ENT>23</ENT>
                            </ROW>
                            <ROW RUL="s">
                                <ENT I="01">
                                    Other 
                                    <SU>2</SU>
                                </ENT>
                                <ENT>9.1</ENT>
                                <ENT>5.3</ENT>
                                <ENT>15</ENT>
                            </ROW>
                            <ROW EXPSTB="03" RUL="s">
                                <ENT I="21">
                                    <E T="02">Leaker Emission Factors—Onshore Petroleum and Natural Gas Production—All Components, Oil Service</E>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">Valve</ENT>
                                <ENT>5.6</ENT>
                                <ENT>3.3</ENT>
                                <ENT>9.2</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Flange</ENT>
                                <ENT>2.7</ENT>
                                <ENT>1.6</ENT>
                                <ENT>4.4</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Connector (other)</ENT>
                                <ENT>5.6</ENT>
                                <ENT>3.2</ENT>
                                <ENT>9.1</ENT>
                            </ROW>
                            <ROW>
                                <PRTPAGE P="42325"/>
                                <ENT I="01">Open-Ended Line</ENT>
                                <ENT>1.6</ENT>
                                <ENT>0.93</ENT>
                                <ENT>2.6</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">
                                    Pump 
                                    <SU>3</SU>
                                </ENT>
                                <ENT>3.7</ENT>
                                <ENT>2.2</ENT>
                                <ENT>6.0</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">
                                    Other 
                                    <SU>2</SU>
                                </ENT>
                                <ENT>2.2</ENT>
                                <ENT>1.0</ENT>
                                <ENT>2.9</ENT>
                            </ROW>
                            <TNOTE>
                                <SU>1</SU>
                                 The open-ended lines component type includes blowdown valve and isolation valve leaks emitted through the blowdown vent stack for centrifugal and reciprocating compressors when using the population emission factor approach as specified in § 98.233(o)(10)(iv) or (p)(10)(iv).
                            </TNOTE>
                            <TNOTE>
                                <SU>2</SU>
                                 “Others” category includes any equipment leak emission point not specifically listed in this table, as specified in § 98.232(c)(21) and (j)(10).
                            </TNOTE>
                            <TNOTE>
                                <SU>3</SU>
                                 The pumps component type in oil service includes agitator seals.
                            </TNOTE>
                        </GPOTABLE>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>23. Remove tables W-3A and W-3B to subpart W of part 98 and add table W-3 to subpart W of part 98 in numerical order to read as follows:</AMDPAR>
                        <GPOTABLE COLS="3" OPTS="L2,i1" CDEF="s100,r100,24">
                            <TTITLE>Table W-3 to Subpart W of Part 98—Default Total Hydrocarbon Population Emission Factors</TTITLE>
                            <BOXHD>
                                <CHED H="1">Industry segment</CHED>
                                <CHED H="1">Source type/component</CHED>
                                <CHED H="1">
                                    Emission factor
                                    <LI>(scf total hydrocarbon/</LI>
                                    <LI>hour/component)</LI>
                                </CHED>
                            </BOXHD>
                            <ROW EXPSTB="02" RUL="s">
                                <ENT I="21">
                                    <E T="02">Population Emission Factors—Storage Wellheads, Gas Service</E>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">Underground natural gas storage</ENT>
                                <ENT>Connector</ENT>
                                <ENT>0.01</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Valve</ENT>
                                <ENT>0.1</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Pressure Relief Valve</ENT>
                                <ENT>0.17</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Open-Ended Line</ENT>
                                <ENT>0.03</ENT>
                            </ROW>
                        </GPOTABLE>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>24. Remove tables W-4A and W-4B to subpart W of part 98 and add table W-4 to subpart W of part 98 in numerical order to read as follows:</AMDPAR>
                        <GPOTABLE COLS="4" OPTS="L2,i1" CDEF="s50,12,12,12">
                            <TTITLE>Table W-4 to Subpart W of Part 98—Default Total Hydrocarbon Leaker Emission Factors</TTITLE>
                            <BOXHD>
                                <CHED H="1">Equipment components</CHED>
                                <CHED H="1">
                                    Emission factor
                                    <LI>(scf total hydrocarbon/hour/component)</LI>
                                </CHED>
                                <CHED H="2">If you survey using Method 21 as specified in § 98.234(a)(2)(i)</CHED>
                                <CHED H="2">If you survey using Method 21 as specified in § 98.234(a)(2)(ii)</CHED>
                                <CHED H="2">If you survey using any of the methods in § 98.234(a)(1), (3), or (5)</CHED>
                            </BOXHD>
                            <ROW EXPSTB="03" RUL="s">
                                <ENT I="21">
                                    <E T="02">Leaker Emission Factors—Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression—Compressor Components, Gas Service</E>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">
                                    Valve 
                                    <SU>1</SU>
                                </ENT>
                                <ENT>14.84</ENT>
                                <ENT>9.51</ENT>
                                <ENT>24.2</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Connector</ENT>
                                <ENT>5.59</ENT>
                                <ENT>3.58</ENT>
                                <ENT>9.13</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Open-Ended Line</ENT>
                                <ENT>17.27</ENT>
                                <ENT>11.07</ENT>
                                <ENT>28.2</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Pressure Relief Valve</ENT>
                                <ENT>39.66</ENT>
                                <ENT>25.42</ENT>
                                <ENT>64.8</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Meter</ENT>
                                <ENT>19.33</ENT>
                                <ENT>12.39</ENT>
                                <ENT>31.6</ENT>
                            </ROW>
                            <ROW RUL="s">
                                <ENT I="01">
                                    Other 
                                    <SU>2</SU>
                                </ENT>
                                <ENT>4.1</ENT>
                                <ENT>2.63</ENT>
                                <ENT>6.70</ENT>
                            </ROW>
                            <ROW EXPSTB="03" RUL="s">
                                <ENT I="21">
                                    <E T="02">Leaker Emission Factors—Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression—Non-Compressor Components, Gas Service</E>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">
                                    Valve 
                                    <SU>1</SU>
                                </ENT>
                                <ENT>6.42</ENT>
                                <ENT>4.12</ENT>
                                <ENT>10.5</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Connector</ENT>
                                <ENT>5.71</ENT>
                                <ENT>3.66</ENT>
                                <ENT>9.3</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Open-Ended Line</ENT>
                                <ENT>11.27</ENT>
                                <ENT>7.22</ENT>
                                <ENT>18.4</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Pressure Relief Valve</ENT>
                                <ENT>2.01</ENT>
                                <ENT>1.29</ENT>
                                <ENT>3.28</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Meter</ENT>
                                <ENT>2.93</ENT>
                                <ENT>1.88</ENT>
                                <ENT>4.79</ENT>
                            </ROW>
                            <ROW RUL="s">
                                <ENT I="01">
                                    Other 
                                    <SU>2</SU>
                                </ENT>
                                <ENT>4.1</ENT>
                                <ENT>2.63</ENT>
                                <ENT>6.70</ENT>
                            </ROW>
                            <ROW EXPSTB="03" RUL="s">
                                <ENT I="21">
                                    <E T="02">Leaker Emission Factors—Underground Natural Gas Storage—Storage Station, Gas Service</E>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">
                                    Valve 
                                    <SU>1</SU>
                                </ENT>
                                <ENT>14.84</ENT>
                                <ENT>9.51</ENT>
                                <ENT>24.2</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Connector (other)</ENT>
                                <ENT>5.59</ENT>
                                <ENT>3.58</ENT>
                                <ENT>9.13</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Open-Ended Line</ENT>
                                <ENT>17.27</ENT>
                                <ENT>11.07</ENT>
                                <ENT>28.2</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Pressure Relief Valve</ENT>
                                <ENT>39.66</ENT>
                                <ENT>25.42</ENT>
                                <ENT>64.8</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Meter and Instrument</ENT>
                                <ENT>19.33</ENT>
                                <ENT>12.39</ENT>
                                <ENT>31.6</ENT>
                            </ROW>
                            <ROW RUL="s">
                                <PRTPAGE P="42326"/>
                                <ENT I="01">
                                    Other 
                                    <SU>2</SU>
                                </ENT>
                                <ENT>4.1</ENT>
                                <ENT>2.63</ENT>
                                <ENT>6.70</ENT>
                            </ROW>
                            <ROW EXPSTB="03" RUL="s">
                                <ENT I="21">
                                    <E T="02">Leaker Emission Factors—Underground Natural Gas Storage—Storage Wellheads, Gas Service</E>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">
                                    Valve 
                                    <SU>1</SU>
                                </ENT>
                                <ENT>4.5</ENT>
                                <ENT>3.2</ENT>
                                <ENT>7.35</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Connector (other than flanges)</ENT>
                                <ENT>1.2</ENT>
                                <ENT>0.7</ENT>
                                <ENT>1.96</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Flange</ENT>
                                <ENT>3.8</ENT>
                                <ENT>2.0</ENT>
                                <ENT>6.21</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Open-Ended Line</ENT>
                                <ENT>2.5</ENT>
                                <ENT>1.7</ENT>
                                <ENT>4.08</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Pressure Relief Valve</ENT>
                                <ENT>4.1</ENT>
                                <ENT>2.5</ENT>
                                <ENT>6.70</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">
                                    Other 
                                    <SU>2</SU>
                                </ENT>
                                <ENT>4.1</ENT>
                                <ENT>2.5</ENT>
                                <ENT>6.70</ENT>
                            </ROW>
                            <TNOTE>
                                <SU>1</SU>
                                 Valves include control valves, block valves and regulator valves.
                            </TNOTE>
                            <TNOTE>
                                <SU>2</SU>
                                 Other includes any potential equipment leak emission point in gas service that is not specifically listed in this table, as specified in § 98.232(d)(7) for onshore natural gas processing, § 98.232(e)(8) for onshore natural gas transmission compression, and as specified in § 98.232(f)(6) and (8) for underground natural gas storage.
                            </TNOTE>
                        </GPOTABLE>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>25. Remove tables W-5A and W-5B to subpart W of part 98 and add table W-5 to subpart W of part 98 in numerical order to read as follows:</AMDPAR>
                        <GPOTABLE COLS="3" OPTS="L2,i1" CDEF="s50,r50,12">
                            <TTITLE>Table W-5 to Subpart W of Part 98—Default Methane Population Emission Factors</TTITLE>
                            <BOXHD>
                                <CHED H="1">Industry segment</CHED>
                                <CHED H="1">Source type/component</CHED>
                                <CHED H="1">
                                    Emission
                                    <LI>factor</LI>
                                    <LI>(scf methane/hour/</LI>
                                    <LI>component)</LI>
                                </CHED>
                            </BOXHD>
                            <ROW EXPSTB="02" RUL="s">
                                <ENT I="21">
                                    <E T="02">Population Emission Factors—LNG Storage Compressor, Gas Service</E>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">LNG storage</ENT>
                                <ENT>
                                    Vapor Recovery Compressor 
                                    <SU>1</SU>
                                </ENT>
                                <ENT>4.17</ENT>
                            </ROW>
                            <ROW RUL="s">
                                <ENT I="01">LNG import and export equipment</ENT>
                            </ROW>
                            <ROW EXPSTB="02" RUL="s">
                                <ENT I="21">
                                    <E T="02">Population Emission Factors—Below Grade Transmission-Distribution Transfer Station Components and Below Grade Metering-Regulating Station</E>
                                     
                                    <SU>2</SU>
                                      
                                    <E T="02">Components, Gas Service</E>
                                     
                                    <SU>3</SU>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">Natural gas distribution</ENT>
                                <ENT>Below Grade T-D Transfer Station</ENT>
                                <ENT>0.30</ENT>
                            </ROW>
                            <ROW RUL="s">
                                <ENT I="22"> </ENT>
                                <ENT>Below Grade M&amp;R Station</ENT>
                                <ENT>0.30</ENT>
                            </ROW>
                            <ROW EXPSTB="02" RUL="s">
                                <ENT I="21">
                                    <E T="02">Population Emission Factors—Distribution Mains, Gas Service</E>
                                     
                                    <SU>4</SU>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">Natural gas distribution</ENT>
                                <ENT>Unprotected Steel</ENT>
                                <ENT>5.1</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Protected Steel</ENT>
                                <ENT>0.57</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Plastic</ENT>
                                <ENT>0.17</ENT>
                            </ROW>
                            <ROW RUL="s">
                                <ENT I="22"> </ENT>
                                <ENT>Cast Iron</ENT>
                                <ENT>6.9</ENT>
                            </ROW>
                            <ROW EXPSTB="02" RUL="s">
                                <ENT I="21">
                                    <E T="02">Population Emission Factors—Distribution Services, Gas Service</E>
                                     
                                    <SU>5</SU>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">Natural gas distribution</ENT>
                                <ENT>Unprotected Steel</ENT>
                                <ENT>0.086</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Protected Steel</ENT>
                                <ENT>0.0077</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Plastic</ENT>
                                <ENT>0.0016</ENT>
                            </ROW>
                            <ROW RUL="s">
                                <ENT I="22"> </ENT>
                                <ENT>Copper</ENT>
                                <ENT>0.03</ENT>
                            </ROW>
                            <ROW EXPSTB="02" RUL="s">
                                <ENT I="21">
                                    <E T="02">Population Emission Factors—Interconnect, Direct Sale, or Farm Tap Stations</E>
                                     
                                    <SU>2</SU>
                                     
                                    <SU>3</SU>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">Onshore natural gas transmission pipeline</ENT>
                                <ENT>Transmission Company Interconnect M&amp;R Station</ENT>
                                <ENT>166</ENT>
                            </ROW>
                            <ROW RUL="s">
                                <ENT I="22"> </ENT>
                                <ENT>Direct Sale or Farm Tap Station</ENT>
                                <ENT>1.3</ENT>
                            </ROW>
                            <ROW EXPSTB="02" RUL="s">
                                <ENT I="21">
                                    <E T="02">Population Emission Factors—Transmission Pipelines, Gas Service</E>
                                     
                                    <SU>4</SU>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">Onshore natural gas transmission pipeline</ENT>
                                <ENT>Unprotected Steel</ENT>
                                <ENT>0.74</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Protected Steel</ENT>
                                <ENT>0.041</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Plastic</ENT>
                                <ENT>0.061</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="22"> </ENT>
                                <ENT>Cast Iron</ENT>
                                <ENT>27</ENT>
                            </ROW>
                            <TNOTE>
                                <SU>1</SU>
                                 Emission Factor is in units of “scf methane/hour/compressor.”
                            </TNOTE>
                            <TNOTE>
                                <SU>2</SU>
                                 Excluding customer meters.
                            </TNOTE>
                            <TNOTE>
                                <SU>3</SU>
                                 Emission Factor is in units of “scf methane/hour/station.”
                                <PRTPAGE P="42327"/>
                            </TNOTE>
                            <TNOTE>
                                <SU>4</SU>
                                 Emission Factor is in units of “scf methane/hour/mile.”
                            </TNOTE>
                            <TNOTE>
                                <SU>5</SU>
                                 Emission Factor is in units of “scf methane/hour/number of services.”
                            </TNOTE>
                        </GPOTABLE>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>26. Remove tables W-6A and W-6B to subpart W of part 98 and add table W-6 to subpart W of part 98 in numerical order to read as follows:</AMDPAR>
                        <GPOTABLE COLS="4" OPTS="L2,i1" CDEF="s50,12,12,12">
                            <TTITLE>Table W-6 to Subpart W of Part 98—Default Methane Leaker Emission Factors</TTITLE>
                            <BOXHD>
                                <CHED H="1">Equipment components</CHED>
                                <CHED H="1">
                                    Emission
                                    <LI>factor (scf methane/hour/</LI>
                                    <LI>component)</LI>
                                </CHED>
                                <CHED H="2">If you survey using Method 21 as specified in § 98.234(a)(2)(i)</CHED>
                                <CHED H="2">If you survey using Method 21 as specified in § 98.234(a)(2)(ii)</CHED>
                                <CHED H="2">If you survey using any of the methods in § 98.234(a)(1), (3), or (5)</CHED>
                            </BOXHD>
                            <ROW EXPSTB="03" RUL="s">
                                <ENT I="21">
                                    <E T="02">Leaker Emission Factors—LNG Storage and LNG Import and Export Equipment—Storage Components and Terminals Components, LNG Service</E>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">Valve</ENT>
                                <ENT>1.19</ENT>
                                <ENT>0.23</ENT>
                                <ENT>1.94</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Pump Seal</ENT>
                                <ENT>4.00</ENT>
                                <ENT>0.73</ENT>
                                <ENT>6.54</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Connector</ENT>
                                <ENT>0.34</ENT>
                                <ENT>0.11</ENT>
                                <ENT>0.56</ENT>
                            </ROW>
                            <ROW RUL="s">
                                <ENT I="01">
                                    Other 
                                    <SU>1</SU>
                                </ENT>
                                <ENT>1.77</ENT>
                                <ENT>0.99</ENT>
                                <ENT>2.9</ENT>
                            </ROW>
                            <ROW EXPSTB="03" RUL="s">
                                <ENT I="21">
                                    <E T="02">Leaker Emission Factors—LNG Storage and LNG Import and Export Equipment—Storage Components and Terminals Components, Gas Service</E>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">
                                    Valve 
                                    <SU>2</SU>
                                </ENT>
                                <ENT>14.84</ENT>
                                <ENT>9.51</ENT>
                                <ENT>24.2</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Connector</ENT>
                                <ENT>5.59</ENT>
                                <ENT>3.58</ENT>
                                <ENT>9.13</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Open-Ended Line</ENT>
                                <ENT>17.27</ENT>
                                <ENT>11.07</ENT>
                                <ENT>28.2</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Pressure Relief Valve</ENT>
                                <ENT>39.66</ENT>
                                <ENT>25.42</ENT>
                                <ENT>64.8</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Meter and Instrument</ENT>
                                <ENT>19.33</ENT>
                                <ENT>12.39</ENT>
                                <ENT>31.6</ENT>
                            </ROW>
                            <ROW RUL="s">
                                <ENT I="01">
                                    Other 
                                    <SU>3</SU>
                                </ENT>
                                <ENT>4.1</ENT>
                                <ENT>2.63</ENT>
                                <ENT>6.70</ENT>
                            </ROW>
                            <ROW EXPSTB="03" RUL="s">
                                <ENT I="21">
                                    <E T="02">Leaker Emission Factors—Natural Gas Distribution—Transmission-Distribution Transfer Station</E>
                                     
                                    <SU>4</SU>
                                      
                                    <E T="02">Components, Gas Service</E>
                                </ENT>
                            </ROW>
                            <ROW EXPSTB="00">
                                <ENT I="01">Connector</ENT>
                                <ENT>1.69</ENT>
                                <ENT/>
                                <ENT>2.76</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Block Valve</ENT>
                                <ENT>0.557</ENT>
                                <ENT/>
                                <ENT>0.91</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Control Valve</ENT>
                                <ENT>9.34</ENT>
                                <ENT/>
                                <ENT>15.3</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Pressure Relief Valve</ENT>
                                <ENT>0.27</ENT>
                                <ENT/>
                                <ENT>0.44</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Orifice Meter</ENT>
                                <ENT>0.212</ENT>
                                <ENT/>
                                <ENT>0.35</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Regulator</ENT>
                                <ENT>0.772</ENT>
                                <ENT/>
                                <ENT>1.26</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Open-ended Line</ENT>
                                <ENT>26.131</ENT>
                                <ENT/>
                                <ENT>42.7</ENT>
                            </ROW>
                            <TNOTE>
                                <SU>1</SU>
                                 “Other” equipment type for components in LNG service should be applied for any equipment type other than connectors, pumps, or valves.
                            </TNOTE>
                            <TNOTE>
                                <SU>2</SU>
                                 Valves include control valves, block valves and regulator valves.
                            </TNOTE>
                            <TNOTE>
                                <SU>3</SU>
                                 “Other” equipment type for components in gas service should be applied for any equipment type other than valves, connectors, flanges, open-ended lines, pressure relief valves, and meters and instruments, as specified in § 98.232(g)(6) and (7) and § 98.232(h)(7) and (8).
                            </TNOTE>
                            <TNOTE>
                                <SU>4</SU>
                                 Excluding customer meters.
                            </TNOTE>
                        </GPOTABLE>
                    </REGTEXT>
                    <REGTEXT TITLE="40" PART="98">
                        <AMDPAR>27. Revise table W-7 to subpart W of part 98 to read as follows:</AMDPAR>
                        <GPOTABLE COLS="2" OPTS="L2,i1" CDEF="s100,10">
                            <TTITLE>Table W-7 to Subpart W of Part 98—Default Methane Emission Factors for Internal Combustion Equipment</TTITLE>
                            <BOXHD>
                                <CHED H="1">
                                    Internal combustion
                                    <LI>equipment type</LI>
                                </CHED>
                                <CHED H="1">
                                    Emission
                                    <LI>factor</LI>
                                    <LI>
                                        (kg CH
                                        <E T="0732">4</E>
                                        /mmBtu)
                                    </LI>
                                </CHED>
                            </BOXHD>
                            <ROW>
                                <ENT I="01">Reciprocating Engine, 2-stroke lean-burn</ENT>
                                <ENT>0.658</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Reciprocating Engine, 4-stroke lean-burn</ENT>
                                <ENT>0.522</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Reciprocating Engine, 4-stroke rich-burn</ENT>
                                <ENT>0.045</ENT>
                            </ROW>
                            <ROW>
                                <ENT I="01">Gas Turbine</ENT>
                                <ENT>0.004</ENT>
                            </ROW>
                        </GPOTABLE>
                    </REGTEXT>
                </SUPLINF>
                <FRDOC>[FR Doc. 2024-08988 Filed 5-13-24; 8:45 am]</FRDOC>
                <BILCOD> BILLING CODE 6560-50-P</BILCOD>
            </RULE>
        </RULES>
    </NEWPART>
</FEDREG>
