| Page Range | 74965-75417 | |
| FR Document |
| Page and Subject | |
|---|---|
| 80 FR 75068 - Sunshine Act Meetings | |
| 80 FR 75129 - Notice of Intent To Collect Fees on Public Land in San Juan County, UT | |
| 80 FR 75051 - Expansion of Subzone 84P, Houston Refining LP, Houston, Texas | |
| 80 FR 75051 - Approval of Subzone Status, Sasol Chemicals (USA), LLC, Calcasieu Parish, Louisiana | |
| 80 FR 75050 - Approval of Subzone Status, Outokumpu Stainless USA, LLC, Calvert, Alabama | |
| 80 FR 75051 - Reorganization of Foreign-Trade Zone 258 Under Alternative Site Framework, Bowie County, Texas | |
| 80 FR 75052 - Reorganization of Foreign-Trade Zone 33 under Alternative Site Framework; Pittsburgh, Pennsylvania | |
| 80 FR 75056 - Welded Line Pipe From the Republic of Korea and the Republic of Turkey: Antidumping Duty Orders | |
| 80 FR 75099 - Extension of Public Comment Period for the National Wetland Condition Assessment 2011 Draft Report | |
| 80 FR 75052 - Polyethylene Terephthalate Film, Sheet, and Strip From the United Arab Emirates; Preliminary Results of Antidumping Duty Administrative Review; 2013-2014 | |
| 80 FR 75054 - Welded Line Pipe From the Republic of Turkey: Countervailing Duty Order | |
| 80 FR 75060 - Aluminum Extrusions From the People's Republic of China: Final Results of Antidumping Duty Administrative Review; 2013-2014 | |
| 80 FR 75074 - Notice of Intent To Grant a Partially/Co-Exclusive License; Envoy Flight Systems, Inc. | |
| 80 FR 75055 - Brass Sheet and Strip From France: Preliminary Results of Antidumping Duty Administrative Review; 2014-2015 | |
| 80 FR 75058 - Antidumping or Countervailing Duty Order, Finding, or Suspended Investigation; Opportunity To Request Administrative Review | |
| 80 FR 75076 - Notice of Intent To Prepare an Environmental Impact Statement/Overseas Environmental Impact Statement for Navy Atlantic Fleet Training and Testing; Correction | |
| 80 FR 75064 - Initiation of Five-Year (“Sunset”) Review | |
| 80 FR 75161 - 60-Day Notice of Proposed Information Collection: Smart Traveler Enrollment Program | |
| 80 FR 75076 - Notice of Intent To Grant a Partially/Co-Exclusive License; CogniTek Management Systems | |
| 80 FR 75075 - Notice of Performance Review Board Membership | |
| 80 FR 75097 - Request for Scientific Views on the Draft Recommended Aquatic Life Ambient Water Quality Criteria for Cadmium-2015 | |
| 80 FR 75075 - Notice of Intent to Prepare an Environmental Impact Statement/Overseas Environmental Impact Statement for Hawaii-Southern California Training and Testing and Notice of Public Scoping Meetings; Correction | |
| 80 FR 75075 - Notice of Intent to Grant Exclusive Patent License: Lockmasters Incorporated | |
| 80 FR 75024 - Cross-State Air Pollution Rule Update for the 2008 Ozone NAAQS | |
| 80 FR 75107 - Medicare Program; Inpatient Prospective Payment Systems; 0.2 Percent Reduction | |
| 80 FR 75148 - Self-Regulatory Organizations; NYSE MKT LLC; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change Establishing Fees for the NYSE MKT Integrated Feed | |
| 80 FR 75141 - Self-Regulatory Organizations; BATS Exchange, Inc.; Notice of Filing of a Proposed Rule Change To Adopt Rule 11.27 Regarding the Data Collection Requirements of the Tick Size Pilot Program | |
| 80 FR 75068 - Defense Advisory Committee on Military Personnel Testing; Notice of Federal Advisory Committee Meeting | |
| 80 FR 75042 - Petitions for Reconsideration and Clarification of Action in Rulemaking Proceeding | |
| 80 FR 75167 - Sanctions Actions Pursuant to Executive Order 13582 | |
| 80 FR 75167 - Additional Identifying Information Associated With Persons Whose Property and Interests in Property Are Blocked Pursuant to Executive Order 13712 of November 23, 2015, “Blocking Property of Certain Persons Contributing to the Situation in Burundi” | |
| 80 FR 75088 - National Fuel Gas Supply Corporation Empire Pipeline, Inc.; Supplemental Notice of Intent to Prepare an Environmental Assessment for the Proposed Northern Access 2016 Project and Request for Comments on Environmental Issues | |
| 80 FR 75068 - 36(b)(1) Arms Sales Notification | |
| 80 FR 75162 - Locomotive Alerters Resetting Without Direct Engineer Action | |
| 80 FR 75072 - 36(b)(1) Arms Sales Notification | |
| 80 FR 75070 - 36(b)(1) Arms Sales Notification | |
| 80 FR 75120 - Proposed Collection; 60-Day Comment Request: NIH Information Collection Forms To Support Genomic Data Sharing for Research Purposes (OD) | |
| 80 FR 74997 - Atlantic Highly Migratory Species; Atlantic Bluefin Tuna Fisheries | |
| 80 FR 74987 - Army Privacy Program | |
| 80 FR 75078 - President's Council of Advisors on Science and Technology | |
| 80 FR 75078 - National Offshore Wind Strategy Workshop | |
| 80 FR 75049 - Notice of Intent To Request Extension, Without Change, of a Currently Approved Information Collection | |
| 80 FR 75043 - Notice of the Specialty Crop Committee's Stakeholder Listening Session | |
| 80 FR 74966 - Changes to Fees and Payment Methods | |
| 80 FR 75049 - Notice of Intent to Request Revision and Extension of a Currently Approved Information Collection. | |
| 80 FR 75008 - Fisheries of the Northeastern United States; Atlantic Bluefish Fishery; Quota Transfer | |
| 80 FR 75102 - Proposed Agency Information Collection Activities; Comment Request | |
| 80 FR 75048 - Notice of Intent To Request Revision and Extension of a Currently Approved Information Collection | |
| 80 FR 75043 - Meeting Notice of the National Agricultural Research, Extension, Education, and Economics Advisory Board | |
| 80 FR 75140 - Proposed Collection; Comment Request | |
| 80 FR 75044 - Agency Information Collection Activities: Proposed Collection; Comment Request-Follow Up to an Assessment of the Roles and Effectiveness of Community-Based Organizations in the Supplemental Nutrition Assistance Program | |
| 80 FR 75132 - Hot-Rolled Steel Products From India; Scheduling of a Countervailing Duty Proceeding Under the Uruguay Round Agreements Act (URAA) | |
| 80 FR 75104 - Change in Bank Control Notices; Acquisitions of Shares of a Bank or Bank Holding Company | |
| 80 FR 75104 - Notice of Proposals to Engage in or to Acquire Companies Engaged in Permissible Nonbanking Activities | |
| 80 FR 75104 - Formations of, Acquisitions by, and Mergers of Bank Holding Companies | |
| 80 FR 75138 - New Postal Product | |
| 80 FR 74985 - Notice of Delay of Discharge Requirements for U.S. Coast Guard Activities in Greater Farallones and Cordell Bank National Marine Sanctuaries | |
| 80 FR 75122 - Current List of HHS-Certified Laboratories and Instrumented Initial Testing Facilities Which Meet Minimum Standards To Engage in Urine Drug Testing for Federal Agencies | |
| 80 FR 75139 - New Postal Product | |
| 80 FR 75125 - Information Collection Request Sent to the Office of Management and Budget (OMB) for Approval; Wolf-Livestock Demonstration Project Grant Program | |
| 80 FR 75091 - BioUrja Power, LLC; Supplemental Notice That Initial Market-Based Rate Filing Includes Request for Blanket Section 204 Authorization | |
| 80 FR 75094 - Shelby County Energy Center, LLC; Supplemental Notice That Initial Market-Based Rate Filing Includes Request for Blanket Section 204 Authorization | |
| 80 FR 75088 - Colonial Eagle Solar, LLC; Supplemental Notice That Initial Market-Based Rate Filing Includes Request For Blanket Section 204 Authorization | |
| 80 FR 75094 - Tennessee Gas Pipeline Company, L.L.C.; Notice Of Intent To Prepare An Environmental Assessment For The Proposed Orion Project And Request For Comments On Environmental Issues | |
| 80 FR 75092 - Combined Notice Of Filings #3 | |
| 80 FR 75093 - Combined Notice Of Filings #2 | |
| 80 FR 75085 - Combined Notice of Filings #1 | |
| 80 FR 75046 - Medicine Bow-Routt National Forests and Thunder Basin National Grassland, Brush Creek/Hayden Ranger District; Wyoming; North Savery Project | |
| 80 FR 75067 - New England Fishery Management Council; Public Meeting | |
| 80 FR 75067 - Gulf of Mexico Fishery Management Council; Public Meetings | |
| 80 FR 75077 - Agency Information Collection Activities; Comment Request; EDFacts Data Collection School Years 2016-17, 2017-18, and 2018-19 | |
| 80 FR 75101 - Notice of Termination; 10437 Palm Desert National Bank, Palm Desert, CA | |
| 80 FR 75101 - Notice of Termination; 10108 First Coweta Bank, Newnan, GA | |
| 80 FR 75101 - Notice of Termination; 10040 Pinnacle Bank, Beaverton, OR | |
| 80 FR 75155 - Self-Regulatory Organizations; Financial Industry Regulatory Authority, Inc.; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change To Extend the Tier Size Pilot of FINRA Rule 6433 (Minimum Quotation Size Requirements for OTC Equity Securities) | |
| 80 FR 75388 - Bloomberg STP LLC; SS&C Technologies, Inc.; Order of the Commission Approving Applications for an Exemption From Registration as a Clearing Agency | |
| 80 FR 75119 - Veterinary Feed Directive Common Format Questions and Answers; Draft Guidance for Industry; Availability | |
| 80 FR 75135 - Proposed Collection, Comment Request | |
| 80 FR 75134 - Agency Information Collection Activities; Submission for OMB Review; Comment Request; Asbestos in Shipyards Standard | |
| 80 FR 75066 - Endangered and Threatened Species; Recovery Plans | |
| 80 FR 75020 - Protection of Human Subjects | |
| 80 FR 75020 - Port of Miami Anchorage Area; Atlantic Ocean, Miami Beach, FL | |
| 80 FR 75076 - Agency Information Collection Activities; Submission to the Office of Management and Budget for Review and Approval; Comment Request; Data Challenges and Appeals Solution (DCAS) | |
| 80 FR 75081 - Lock Hydro Friends Fund III; Notice of Preliminary Permit Application Accepted for Filing and Soliciting Comments, Motions To Intervene, and Competing Applications | |
| 80 FR 75081 - Energy Resources USA Inc., Notice of Preliminary Permit Application Accepted for Filing and Soliciting Comments and Motions To Intervene | |
| 80 FR 75080 - Energy Resources USA Inc.; Notice of Preliminary Permit Application Accepted for Filing and Soliciting Comments and Motions To Intervene | |
| 80 FR 75093 - Lock Hydro Friends Fund III; Notice of Preliminary Permit Application Accepted for Filing and Soliciting Comments, Motions To Intervene, and Competing Applications | |
| 80 FR 75097 - Notice of Commission Staff Attendance | |
| 80 FR 75079 - Magnum Gas Storage, LLC; Notice of Application for Amendment | |
| 80 FR 75091 - Tennessee Gas Pipeline Company, L.L.C; Notice of Schedule for Environmental Review of the Susquehanna West Project | |
| 80 FR 75079 - Combined Notice of Filings | |
| 80 FR 75086 - Combined Notice of Filings #1 | |
| 80 FR 75083 - Columbia Gas Transmission, LLC; Notice of Intent To Prepare an Environmental Impact Statement for the Planned Mountaineer XPress Project, Request for Comments on Environmental Issues and Notice of Public Scoping Meeting | |
| 80 FR 75080 - New England Hydropower Company, LLC; Notice of Surrender of Preliminary Permit | |
| 80 FR 75082 - RE Astoria 2 LLC; Supplemental Notice That Initial Market-Based Rate Filing Includes Request for Blanket Section 204 Authorization | |
| 80 FR 75096 - RE Astoria LLC; Supplemental Notice That Initial Market-Based Rate Filing Includes Request for Blanket Section 204 Authorization | |
| 80 FR 75087 - Cogentrix Virginia Financing Holding Company, LLC; Supplemental Notice That Initial Market-Based Rate Filing Includes Request for Blanket Section 204 Authorization | |
| 80 FR 75082 - Ohio Valley Electric Corporation; Supplemental Notice That Initial Market-Based Rate Filing Includes Request For Blanket Section 204 Authorization | |
| 80 FR 75091 - PáTu Wind Farm, LLC v. Portland General Electric Company, PáTu Wind Farm, LLC; Notice of Complaint | |
| 80 FR 75087 - Combined Notice of Filings #1 | |
| 80 FR 75100 - Information Collections Being Submitted for Review and Approval to the Office of Management and Budget | |
| 80 FR 75157 - Self-Regulatory Organizations; NASDAQ OMX BX, Inc.; Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Establish Fees and Rebates Related to BX Price Improvement Auction (PRISM) | |
| 80 FR 75147 - Self-Regulatory Organizations; The NASDAQ Stock Market LLC; Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Include Managed Fund Shares in the Lead Market Maker Program | |
| 80 FR 75169 - Proposed Collection; Comment Request for Regulation Project | |
| 80 FR 75170 - Proposed Collection; Comment Request for Notice 2012-48 | |
| 80 FR 75136 - Records Schedules; Availability and Request for Comments | |
| 80 FR 75173 - Proposed Collection; Comment Request for Revenue Procedure 2006-16 | |
| 80 FR 75171 - Proposed Collection; Comment Request for Form 8613 | |
| 80 FR 75172 - Proposed Collection; Comment Request for Notice 97-34 | |
| 80 FR 75170 - Proposed Collection; Comment Request for Form 8918 | |
| 80 FR 75168 - Proposed Collection; Comment Request for Information Collection | |
| 80 FR 75070 - Defense Transportation Regulation, Part IV | |
| 80 FR 75099 - Stratospheric Protection Division; Teleconference on the Clean Air Act Section 608 Technician Certification Program Test Bank | |
| 80 FR 75045 - Uinta-Wasatch-Cache National Forest and Ashley National Forest; Utah; High Uintas Wilderness Domestic Sheep Analysis | |
| 80 FR 75139 - Product Change-Priority Mail Express and Priority Mail Negotiated Service Agreement | |
| 80 FR 75140 - Product Change-Priority Mail Negotiated Service Agreement | |
| 80 FR 75171 - Proposed Collection; Comment Request for Regulation Project | |
| 80 FR 75173 - Proposed Collection; Comment Request for Information Collection | |
| 80 FR 75139 - Product Change-Priority Mail Express, Priority Mail, & First-Class Package Service Negotiated Service Agreement | |
| 80 FR 75174 - Office of the Assistant Secretary for International Affairs; Survey of U.S. Ownership of Foreign Securities as of December 31, 2015 | |
| 80 FR 75025 - Supplemental Finding That It Is Appropriate and Necessary To Regulate Hazardous Air Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units | |
| 80 FR 75018 - Rules and Regulations Under the Trade Regulation Rule Concerning Preservation of Consumers' Claims and Defenses | |
| 80 FR 75105 - Progressive Chevrolet Company and Progressive Motors, Inc.; Analysis of Proposed Consent Order To Aid Public Comment | |
| 80 FR 75106 - Office for State, Tribal, Local and Territorial Support (OSTLTS); Meeting and Tribal Consultation Session | |
| 80 FR 75009 - Uninterruptible Monitoring of Coolant and Fuel in Reactors and Spent Fuel Pools | |
| 80 FR 75125 - Washington; Amendment No. 1 to Notice of a Major Disaster Declaration | |
| 80 FR 75124 - South Carolina; Amendment No. 12 to Notice of a Major Disaster Declaration | |
| 80 FR 75124 - Alaska; Major Disaster and Related Determinations | |
| 80 FR 75122 - Center for Scientific Review; Notice of Closed Meetings | |
| 80 FR 75125 - California; Amendment No. 6 to Notice of a Major Disaster Declaration | |
| 80 FR 74988 - Special Regulations, Areas of the National Park System, Lake Chelan National Recreation Area, Solid Waste Disposal | |
| 80 FR 75022 - Special Regulations, Areas of the National Park System, Rocky Mountain National Park | |
| 80 FR 74965 - Uniform Administrative Requirements, Cost Principles, and Audit Requirements for Federal Awards; Updating References | |
| 80 FR 75134 - Meeting of the Judicial Conference Committee on Rules of Practice and Procedure | |
| 80 FR 75163 - Proposed Collection of Information: TreasuryDirect System | |
| 80 FR 75163 - Martin Marietta Materials, Inc.-Acquisition of Control Exemption-Rock & Rail LLC | |
| 80 FR 75174 - Notice of Performance Review Board Members | |
| 80 FR 75117 - Proposed Information Collection Activity; Comment Request | |
| 80 FR 75134 - Notice of Lodging of Proposed Consent Decree Under the Residential Lead-Based Paint Hazard Reduction Act | |
| 80 FR 75356 - Takes of Marine Mammals Incidental to Specified Activities; Marine Geophysical Survey in the South Atlantic Ocean, January to March 2016 | |
| 80 FR 74966 - Highly Fractionated Indian Land (HFIL) Loan Program | |
| 80 FR 74982 - Airworthiness Directives; Airbus Helicopters | |
| 80 FR 74986 - Allocation of Assets in Single-Employer Plans; Valuation of Benefits and Assets; Expected Retirement Age | |
| 80 FR 75164 - Update to the List of Medical Supplies | |
| 80 FR 75130 - Petroleum Wax Candles from China; Institution of a Five-Year Review | |
| 80 FR 75126 - Deepwater Horizon | |
| 80 FR 74974 - Miscellaneous Corrections | |
| 80 FR 75010 - Liquidity Coverage Ratio: Public Disclosure Requirements; Extension of Compliance Period for Certain Companies To Meet the Liquidity Coverage Ratio Requirements | |
| 80 FR 74999 - Atlantic Highly Migratory Species; 2016 Atlantic Shark Commercial Fishing Season | |
| 80 FR 74991 - Expanded Access to Non-VA Care Through the Veterans Choice Program | |
| 80 FR 75178 - Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards |
Agricultural Research Service
Farm Service Agency
Food and Nutrition Service
Forest Service
National Agricultural Statistics Service
Foreign-Trade Zones Board
International Trade Administration
National Oceanic and Atmospheric Administration
Army Department
Navy Department
Energy Efficiency and Renewable Energy Office
Federal Energy Regulatory Commission
Centers for Disease Control and Prevention
Centers for Medicare & Medicaid Services
Children and Families Administration
Food and Drug Administration
National Institutes of Health
Substance Abuse and Mental Health Services Administration
Coast Guard
Federal Emergency Management Agency
Fish and Wildlife Service
Land Management Bureau
National Park Service
Labor Statistics Bureau
Federal Aviation Administration
Federal Railroad Administration
Surface Transportation Board
Fiscal Service
Foreign Assets Control Office
Internal Revenue Service
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.
To subscribe to the Federal Register Table of Contents LISTSERV electronic mailing list, go to http://listserv.access.thefederalregister.org and select Online mailing list archives, FEDREGTOC-L, Join or leave the list (or change settings); then follow the instructions.
Department of Veterans Affairs.
Final rule.
This rule adopts as final, without change, interim final rule amending the Department of Veterans Affairs (VA) regulations governing Office of Management and Budget (OMB) citations and references for federal grant programs. This amendment is necessary to replace obsolete OMB references in VA regulations.
Brian McCarthy, Office of Regulatory and Administrative Affairs (10B4), Veterans Health Administration, Department of Veterans Affairs, 810 Vermont Ave. NW., Washington, DC 20420, (202) 461-6345. (This is not a toll-free telephone number.)
On December 19, 2014, OMB published a joint interim final rule in the
Executive Orders 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, when regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, and other advantages; distributive impacts; and equity). Executive Order 13563 (Improving Regulation and Regulatory Review) emphasizes the importance of quantifying both costs and benefits, reducing costs, harmonizing rules, and promoting flexibility. Executive Order 12866 (Regulatory Planning and Review) defines a “significant regulatory action,” which requires review by the Office of Management and Budget (OMB), unless OMB waives such review, as “any regulatory action that is likely to result in a rule that may: (1) Have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities; (2) Create a serious inconsistency or otherwise interfere with an action taken or planned by another agency; (3) Materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or (4) Raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in this Executive Order.”
The economic, interagency, budgetary, legal, and policy implications of this regulatory action have been examined, and it has been determined not to be a significant regulatory action under Executive Orders 12866. VA's impact analysis can be found as a supporting document at
The Regulatory Flexibility Act (RFA) requires an agency that is issuing a final rule to provide a final regulatory flexibility analysis or to certify that the rule will not have a significant economic impact on a substantial number of small entities. This final rule implements OMB final guidance issued on December 26, 2013, and will not have a significant economic impact beyond the impact of the December 2013 guidance.
The Unfunded Mandates Reform Act of 1995 requires, at 2 U.S.C. 1532, that agencies prepare an assessment of anticipated costs and benefits before issuing any rule that may result in the expenditure by State, local, and tribal governments, in the aggregate, or by the private sector, of $100 million or more (adjusted annually for inflation) in any one year. This final rule will have no such effect on State, local, and tribal governments, or on the private sector.
This final rule contains no provisions constituting a collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3521).
The Catalog of Federal Domestic Assistance numbers and titles for the programs affected by this document are 64.005, Grants to States for Construction of State Home Facilities; 64.024, VA Homeless Providers Grant and Per Diem Program; 64.026, Veterans State Adult Day Health Care; 64.033, VA Supportive Services for Veteran Families Program; 64.034, VA Assistance to United States Paralympic Integrated Adaptive Sports Program; 64.037, VA U.S. Paralympics Monthly Assistance Allowance Program; 64.038, Grants for the Rural Veterans Coordination Pilot; 64.100, Automobiles and Adaptive Equip for Certain Disabled Vets and Members of the Armed Forces; 64.201, National Cemeteries; and 64.203, State Cemetery Grants.
The Secretary of Veterans Affairs, or designee, approved this document 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. Robert L. Nabors II, Chief of Staff, Department of Veterans Affairs,
Agricultural Research Service, USDA.
Final rule.
The Agricultural Research Service (ARS) increases its Patent Culture Collection charges, and revises the method of payment.
This rule is effective December 1, 2015.
Jeffrey Kurtz, ARS-Budget and Program Management Staff, George Washington Carver Center, 5601 Sunnyside Avenue, Room 4-1106, Beltsville, Maryland, 20705, telephone: (301) 504-4494, email:
Microbial-based agriculture and biotechnology rely on superior production strains, new strains with novel characteristics, and reference strains for comparative purposes. Such strains are often difficult to acquire or are cost prohibitive for many researchers. ARS has a staff dedicated to the acquisition and distribution of microbial germplasm in which patented strains can be deposited in and distributed from its Patent Culture Collection for a one-time fee to cover maintenance and distribution costs.
ARS' Patent Culture Collection receives about 120 patent deposits per year, and distributes about 450 cultures per year. Nearly all of the accessions and distributions are requested by companies, universities, or Government agencies. Currently, ARS charges $500 for each microbial culture deposit, as set forth in 7 CFR 504.2(a). For each microbial culture distribution ARS charges $20, as set forth in 7 CFR 504.2(b). The current fees, which were established in 1985, did not reflect the actual costs of providing materials and services. ARS is increasing these fees to reflect their actual costs of $670 and $40, respectively, and to apply the distribution fee to all patent deposits regardless of the date of the deposit.
Currently, payment for deposit and requisition of microbial cultures is made by check, draft, or money order payable to the USDA, National Finance Center, as set forth in 7 CFR 504.3(b). ARS is adding
The increased fees will enable ARS' Patent Culture Collection to continue its mission of supporting microbiological research and biotechnological innovation, and serve as a repository where patented microbial strains can be deposited and distributed to the scientific community. All of the current services will continue to be offered under the revised fee schedule and method of payment.
This rule was published as a proposed rule for comment on September 2, 2015. See 80 FR 53021, September 2, 2015. No comments were received.
Agricultural research.
For reasons set forth in the preamble, ARS amends 7 CFR part 504 as set forth below:
31 U.S.C. 9701.
(a) Depositors of microbial cultures must pay a one-time $670 user fee for each culture deposited on or after December 1, 2015.
(b) For cultures deposited on or after December 1, 2015, requestors must pay a $40 user fee for each culture distributed.
(a) Payment of user fees must accompany a culture deposit or request.
(b) Payment shall be made by check, draft, money order, or
Farm Service Agency, USDA.
Final rule.
The Farm Service Agency (FSA) is implementing the HFIL Loan Program to provide revolving loan funds to eligible intermediary lenders familiar with Indian Lands. The intermediary lenders will provide loan funds to qualified individuals, entities, and tribes to purchase highly fractionated Indian land consistent with the Agricultural Act of 2014 (2014 Farm Bill). FSA is also requesting public comments on the rule.
We invite you to submit comments on the rule. In your comment, include the Regulation Identifier Number (RIN), the volume, date, and page number of this issue of the
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Comments will be available online at
Carrie Novak; telephone; (202) 720-1643. Persons with disabilities or who require alternative means for communication should contact the USDA Target Center at (202) 720-2600 (voice).
The HFIL Loan Program is authorized by the section 5402 of the 2014 Farm
As a result of the General Allotment Act of 1887 (also commonly known as the Dawes Act), Indian reservation land was allotted to individual tribal members. When an allottee died, title ownership was divided among his or her heirs, but the land itself was not partitioned and, as such, each Indian heir received an undivided interest in the land. As each generation passes, the number of owners grows exponentially. This has resulted in the highly fractionated ownership of much of the nation's Indian land. As ownership of Indian land descends from one generation to another, the long standing problem of fractionation continues to worsen as many tracts are owned by hundreds or even thousands of individuals. The ability of the owners to use land decreases as fractionation increases, sometimes to the point where it is nearly impossible to locate the owners or for the known owners to coordinate the use of the property. The HFIL Loan Program will help encourage intermediary lenders to provide loans to individual tribal members in order to resolve the highly fractionated ownership of land.
To ensure the HFIL Loan Program would have the greatest chance of success, FSA held a Tribal Consultation session on December 10, 2014. Recommendations on issues discussed during the Tribal Consultation have been addressed in this rule.
Some definitions in this rule originate from other already established laws and regulations and are used here for consistency. Indian Country uses the definition in 18 U.S.C. 1151. “Native American Tribe” and “Tribal Entity” definitions are consistent with 7 U.S.C. 770, “Indian Tribal Land Acquisition Program.” HFIL will be defined as undivided interests held by four or more individuals. The definition in 25 U.S.C. 2201 defines highly fractionated as 50 or more undivided owners. A less constraining definition is needed for this rule in order for the HFIL Loan Program to effectively meet the objectives of consolidating fractionated interests. Tribal Consultation indicated that not all fractionated parcels have 50 or more owners and using the strict definition could exclude the parcels from the HFIL Loan Program.
In addition, § 761.2 needs to be revised to specify that the products of tree farming and the products of other plant and animal production are agricultural commodities. Therefore, this rule also revises the definition of “Agricultural Commodity” in § 761.2 as a conforming change. The intention of the list of items that are considered agricultural commodities has not changed; it is strictly correcting the language in the definition.
Through Tribal Consultation, it became apparent to FSA that the most important characteristics of an intermediary lender are the knowledge and familiarity of working with Indian Country and experience working with BIA. The list of entities in § 769.103 should be flexible enough to include any qualifying entity interested in participating in the HFIL Loan Program.
FSA will develop guidelines for and provide loan funds to the intermediary lenders, who will facilitate the purchase and consolidation of fractionated interest by relending the funds to qualified tribes, individuals, and entities. FSA will establish criteria in § 769.103(b) and (c) for the intermediary lender that will be tied to the organization's demonstrated skills, ability, and knowledge of working with Indian land. The intermediary lender will establish eligibility criteria for the ultimate recipient as restricted by this rule in § 769.104.
An ultimate recipient is an entity or individual that receives a loan from an intermediary's HFIL revolving fund. The eligibility requirements of the ultimate recipient in § 769.104 are restrictive because this program is limited by the provisions of the 2014 Farm Bill; therefore, only Tribes, individual Tribal members, and Tribal entities are eligible to apply. In addition, the 2014 Farm Bill authorizes the HFIL Loan Program under 25 U.S.C. 488 rather than the Consolidated Farm and Rural Development Act (CONACT, 7 U.S.C. 1911-2008r) where most FSA loan programs are authorized. Accordingly, the FSA loan is to the intermediary lender as authorized under 25 U.S.C. 488 and the CONACT requirements regarding credit elsewhere and maximum loan amounts which typically apply to applicants of the FSA Farm Loan Programs do not apply to the intermediary or the ultimate recipient.
The purposes of the HFIL Loan Program are very specific and funds can only be used for the purchase of HFIL and related expenses as specified in §§ 769.105 and 769.106.
The HFIL Loan Program is subject to environmental compliance provisions specified in 7 CFR part 1940, subpart G. Accordingly, each intermediary lender will provide FSA with documentation of its process to address environmental issues on the land to be purchased.
The Tribal Consultation resulted in the strong recommendation that the ultimate recipient be limited in use of loan funds to purchasing land for an agricultural use for the term of the loan. The requirement to qualify for HFIL loans is contained in this rule in § 769.106.
The rate of interest for the intermediary lender will be set annually, but will not be less than 1 percent and the maximum HFIL loan term is 30 years. The intermediary lender will relend at a rate of interest and term negotiated with the ultimate recipient in a manner detailed in the Intermediary Relending Agreement approved by FSA.
The Intermediary Relending Agreement will contain the policies and procedures that the intermediary lender will follow with respect to the loan and the working relationship with the ultimate recipients. This will provide maximum flexibility for the intermediary lender to work with its ultimate recipient on loan making and loan servicing and will be approved by FSA prior to the HFIL loan closing. The required elements of the agreement are specified in § 769.103(d). The agreement and requirements are similar to the requirements in § 762.106 that must be met by FSA guaranteed lenders seeking certification as a preferred lender.
An intermediary lender will be required to have a revolving loan fund.
Primary security for the HFIL Loan Program will be in the form of a first lien in the intermediary lender's revolving loan fund. Additional security will be required if needed to fully secure the loan.
FSA determined that yearly monitoring reports would be both necessary for the success of the program and beneficial to the intermediary lender. FSA did not want to be over burdensome in the required type of reporting or audits and therefore adopted an approach similar to what has been successfully used in the Boll Weevil Eradication Loan Program in 7 CFR part 77.
This rule is adding § 769.124 to allow for transfer and assumptions of the HFIL loans in the event that an intermediary lender should want or need to discontinue participation in the HFIL Loan Program.
The Administrative Procedure Act (5 U.S.C. 553) provides generally that before rules are issued by Government agencies, the rule is required to be published in the
Executive Order 12866, “Regulatory Planning and Review,” and Executive Order 13563, “Improving Regulation and Regulatory Review,” direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility.
The Office of Management and Budget (OMB) designated this rule as not significant under Executive Order 12866 and, therefore, OMB has not reviewed this final rule.
The Regulatory Flexibility Act (5 U.S.C. 601-612), as amended by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), generally requires an agency to prepare a regulatory flexibility analysis of any rule whenever an agency is required by the APA or any other law to publish a proposed rule, unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. This rule is exempt from notice and comment rulemaking requirements of the APA and no other law requires that a proposed rule be published for this rulemaking initiative.
The environmental impacts of this rule have been considered in a manner consistent with the provisions of the National Environmental Policy Act (NEPA, 42 U.S.C. 4321-4347), the regulations of the Council on Environmental Quality (40 CFR parts 1500-1508), and the FSA regulations for compliance with NEPA (7 CFR part 1940, subpart G). This rule is to implement the new HFIL Loan Program, a program created by the 2014 Farm Bill. The discretionary provisions needed to implement the HFIL Loan Program, specifically those relating to our loans to the intermediary lenders include the loan making and servicing rules, which will mirror present FLP regulations. One discretionary provision that will not mirror current FSA rules is that implementation will be through an intermediary lender that will relend the funds, an approach that will be a new lending tool for FSA. The process FSA will use to administer the intermediary lending model was vetted through and determined to be acceptable by a Tribal consultation, held on December 10, 2014, at the Intertribal Agricultural Council annual meeting. As the provisions needed to implement this rule are all administrative in nature, FSA will not prepare an environmental assessment or environmental impact statement for this regulatory action.
Executive Order 12372, “Intergovernmental Review of Federal Programs,” requires consultation with State and local officials. The objectives of the Executive Order are to foster an intergovernmental partnership and a strengthened Federalism, by relying on State and local processes for State and local government coordination and review of proposed Federal Financial assistance and direct Federal development. For reasons set forth in the final rule related notice regarding 7 CFR part 3015, subpart V (48 FR 29115, June 24, 1983), the programs and activities within this rule are excluded from the scope of Executive Order 12372.
This rule has been reviewed in accordance with Executive Order 12988, “Civil Justice Reform.” This rule will not preempt State or local laws, regulations, or policies unless they represent an irreconcilable conflict with this rule. The rule does not have retroactive effect. Before any judicial action may be brought regarding the provisions of this rule, the administrative appeal provisions of 7 CFR parts 11 and 780 are to be exhausted.
This rule has been reviewed under Executive Order 13132, “Federalism.” The policies contained in this rule do not have any substantial direct effect on 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. Nor would this rule impose substantial direct compliance costs on State and local governments. Therefore, consultation with the States is not required.
This rule has been reviewed for compliance with Executive Order 13175, “Consultation and Coordination with Indian Tribal Governments.” Executive Order 13175 imposes requirements on the development of regulatory policies that have Tribal implications or preempt Tribal laws. The USDA Office of Tribal Relations has concluded that the policies contained in this rule do not, to USDA's knowledge, preempt Tribal law.
Rulemaking to address the issue of HFIL was initially considered as part of the implementation of the Food, Conservation, and Energy Act of 2008 (Pub. L. 110-246, known as the 2008 Farm Bill). An HFIL loan program was authorized by the 2008 Farm Bill; however, the language required that the program operate as a direct loan program in which FSA would make loans directly to the ultimate recipients. During 2010, USDA held two sets of face-to-face Tribal consultation sessions across the country. FSA Farm Loan Programs held seven Tribal consultation sessions specifically to discuss the HFIL Loan Program (section 5501 of the 2008 Farm Bill) in the following locations on the following dates:
FSA Farm Loan Programs also participated in an additional seven Tribal consultation sessions across the country to discuss the 2008 Farm Bill changes, including the HFIL Loan Program. The USDA 2008 Farm Bill Tribal consultations were held in the following locations on the following dates:
Early on, during the 2008 Farm Bill Tribal consultations, FSA heard the various concerns that were raised and thought a workable solution could still be found to implement the HFIL Loan Program; however, as additional concerns continued to be raised and differences were identified in other regions of the country, it became clear that one of the problems was that the 2008 Farm Bill provision was tied to the BIA definition of highly fractionated and as such would also be tied to the BIA procedures for clearing titles, so it was determined that a regulation would not result in a successful program for Indian country. FSA listened and heard concerns about the land being too fractionated, the process being too complicated, the difficulties in really understanding the issues that caused the fractionation, problems with consolidation, and related cultural issues. In addition to the complexity of the BIA process for clearing titles for fractionated land, the results were different across the country. In one example, it took 6 months to clear a title, in another example, clearing a title took 10 years. There were suggestions that the HFIL Loan Program would work if FSA worked with existing Native American organizations that were already established to consolidate fractionated land and make it a relending program.
As a direct result of everything that FSA heard and learned throughout the 2008 Farm Bill Tribal consultations, FSA provided input for the new requirements in the 2014 Farm Bill to work out a way to make the regulations effective for Indian Country by incorporating the option for an intermediary lender to relend the funds and remove the tie to the BIA definition of highly fractionated.
For the development of this rule, a Tribal consultation was held on December 10, 2014, at the Intertribal Agricultural Council annual meeting. The participants in the Tribal consultation have strongly supported the HFIL Loan Program. During the Tribal consultation, FSA staff asked for and received feedback on the following proposed provisions of the HFIL Loan Program.
HFIL Proposed Provision: Should the HFIL Loan Program be administered as a relending program?
Tribal Consultation Response: Yes.
HFIL Proposed Provision: Should there be a minimum number of acres consolidated with the HFIL Loan Program?
Tribal Consultation Response: No.
HFIL Proposed Provision: Should there be a limited number of intermediary lenders?
Tribal Consultation Response: Yes, given the limited amount of funds, approved intermediary lenders should be limited to no more than two lenders per year.
HFIL Proposed Provision: Should there be any restrictions to the use of funds under the HFIL Loan Program?
Tribal Consultation Response: Yes, funds should be used only for the consolidation of agricultural land.
During the 90-day comment period for this rule, FSA will schedule additional Tribal consultation on the HFIL Loan Program. Although FSA is making this rule effective on publication, FSA will work on changes to the regulation as needed based on comments and
In addition, to developing the HFIL Loan Program, FSA will continue to engage with Tribal organizations to ensure HFIL Loan Program rules are consistent with Tribal laws and so that the HFIL Loan Program has a maximum opportunity for success. USDA will continue to coordinate with Tribal governmental organizations concerning this rule and will provide appropriate venues, such as webinars and teleconferences, to host collaborative conversations with Tribal leaders and their representatives concerning ways to improve this rule in Indian country.
Title II of the Unfunded Mandate Reform Act of 1995 (UMRA, Pub. L. 104-4) requires Federal agencies to assess the effects of their regulatory actions on State, local, or Tribal governments or the private sector. Agencies generally must prepare a written statement, including a cost benefit analysis, for proposed and final rules with Federal mandates that may result in expenditures of $100 million or more in any 1 year for State, local, or Tribal governments, in the aggregate, or to the private sector. UMRA generally requires agencies to consider alternatives and adopt the more cost effective or least burdensome alternative that achieves the objectives of the rule. This rule contains no Federal mandates under the regulatory provisions of Title II of the Unfunded Mandates Reform Act of 1995 for State, local, or Tribal governments, or the private sector. Therefore, this rule is not subject to the requirements of sections 202 and 205 of UMRA.
FSA will not be collecting any information from the ultimate recipients in the HFIL Loan Program. There are some reporting requirements on the HFIL Loan Program activities from intermediary lenders to FSA. The intermediary lenders must allow FSA to review the ultimate recipients' records; the intermediary lenders maintain the records are expected to be a part of customary and usual business practices for the process of loans. Therefore, the burden associated with recordkeeping is excluded. The intermediary lenders will be an entity that meets certain criteria to be established by FSA such as: Has been active in the previous 5 years, and has expertise in technical assistance, is an established financial organization which is regulated by an acceptable state or federal regulatory agency, meets certain capital requirements, and ability to work with the Bureau of Indian Affairs (BIA). FSA will lend funds to an eligible entity, which will then relend directly to a Tribe or an individual. There are limited entities that will qualify to be intermediary lenders for the HFIL Loan Program. The current annual allocation of $10 million will not sufficiently fund multiple intermediaries. For the HFIL Loan Program to be effective adequate funds must be available for each intermediary lender to borrow to relend. As discussed above, at the Tribal Consultation held on December 10, 2014, members in attendance strongly suggested that HFIL Loan Program be restricted to no more than 2 intermediary lenders per year for funding due to limited funding. FSA expects to have less than 10 intermediary lenders eligible to participate in the HFIL Loan Program annually. Therefore, this would not require OMB approval under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).
FSA is committed to complying with the E-Government Act, to promote the use of the Internet and other information technologies to provide increased opportunities for citizen access to Government information and services, and for other purposes.
Accounting, Loan programs-agriculture, Rural areas.
Loan program-Agriculture, Indians
For the reasons discussed above, FSA amends 7 CFR chapter VII as follows:
5 U.S.C. 301 and 7 U.S.C. 1989.
The revision reads as follows:
(b) * * *
5 U.S.C. 301, 7 U.S.C. 1989, and 25 U.S.C. 488.
(a) This part contains regulations for loans made by the Agency to eligible intermediary lenders and applies to intermediary lenders and ultimate recipient involved in making and servicing Highly Fractionated Indian Land (HFIL) loans.
(b) The purpose of the HFIL Loan Program is to establish policies and procedures for a revolving loan fund through intermediary lenders for the purchase of HFIL by a Native American tribe, tribal entity, or member of either.
(a)
(b)
(1) All land within the limits of any Indian reservation under the jurisdiction of the U.S. Government, notwithstanding the issuance of any patent, and, including rights-of-way running through the reservation,
(2) All dependent Indian communities within the borders of the United States whether within the original or subsequently acquired territory thereof, and whether within or without the limits of a state, and
(3) All Indian allotments, the Indian titles to which have not been extinguished, including rights-of-way running through the same; or
(4) All land, communities, and allotments that meet the definition of 18 U.S.C. 1151.
(1) An Indian tribe recognized by the U.S. Department of the Interior; or
(2) A community in Alaska incorporated by the U.S. Department of the Interior pursuant to the Indian Reorganization Act.
(a)
(1) Private and Tribal operated nonprofit corporations;
(2) Public agencies—Any State or local government, or any branch or agency of such government having authority to act on behalf of that government, borrow funds, and engage in activities eligible for funding under this part;
(3) Indian tribes or tribal corporations; or
(4) Lenders who are subject to credit examination and supervision by an acceptable State or Federal regulatory agency.
(b)
(1) Have the legal authority necessary for carrying out the proposed loan purposes and for obtaining, giving security for, and repaying the proposed loan;
(2) Have a record of successful lending in Indian Country and knowledge and experience working with the BIA. The Agency will assess the applicant staff's training and experience in lending in Indian Country based on recent experience in loan making and servicing with loans that are similar in nature to the HFIL program. If consultants will be used, FSA will assess the staff's experience in choosing and supervising consultants; and
(3) Have an adequate assurance of repayment of the loan based on the fiscal and managerial capabilities of the proposed intermediary lender.
(c)
(1) Loan documentation requirements including planned application forms, security instruments, and loan closing documents;
(2) List of proposed fees and other charges it will assess the ultimate recipients;
(3) The plan for relending the loan funds. The plan must have sufficient detail to provide the Agency with a complete understanding of the complete mechanics of how the funds will get from the intermediary lender to the ultimate recipient. Included in the plan are the service area, eligibility criteria, loan purposes, rates, terms, collateral requirements, a process for addressing environmental issues on property to be purchased, limits, priorities, application process, analysis of new loan requests, and method of disbursement of the funds to the ultimate recipient;
(4) Loan review plans that specify how the intermediary lender will review the loan request from the ultimate recipient and make an eligibility determination;
(5) An explanation of the intermediary lender's established internal credit review process; and
(6) An explanation of how the intermediary lender will monitor the loans to the ultimate recipients.
(a) Ultimate recipients must be individual Tribal members, Tribes or eligible Tribal entities, with authority to incur the debt and carry out the purpose of the loan.
(b) The intermediary lender will make this determination in accordance with the Intermediary Relending Agreement.
(a)
(b)
(1) Must be used to acquire and consolidate at least 50 percent of the highly fractionated Indian land parcel and interests in the land. The interests include rights-of-way, water rights, easements, and other appurtenances that would normally pass with the land or are necessary for the proposed operation of the land located within the tribe's reservation;
(2) Must finance land that will be used for agricultural purposes during the term of the loan;
(3) May be used to pay costs incidental to land acquisition, including, but not limited to, title clearance, legal services, archeological or land surveys, and loan closing; and
(4) May be used to pay for the costs of any appraisal conducted in accordance with this part.
(a) Loan funds may not be used for any land improvement or development purposes, acquisition or repair of buildings or personal property, payment of operating costs, payment of finders' fees, or similar costs, or for any purpose that will contribute to excessive erosion of highly erodible land or to the conversion of wetlands to produce an agricultural commodity as specified in 7 CFR part 12.
(b) The amount of loan funds used to acquire land may not exceed the current market value of the land as determined by a current appraisal that meets the requirements as specified in 7 CFR 761.7(b)(1).
(c) Agency HFIL loan funds may not be used for payment of the intermediary's administrative costs or expenses. The amount removed from the HFIL revolving fund for administrative costs in any year must be reasonable, must not exceed the actual cost of operating the HFIL revolving fund and must not exceed the amount approved by the Agency in the intermediary lender's annual loan monitoring report.
(d) No loan to an intermediary lender may exceed the maximum amount the intermediary can reasonably expect to lend to eligible ultimate recipients, based on anticipated demand for loans to consolidate fractioned interests and capacity of the intermediary to effectively carry out the terms of the loan.
(a) Loans made by the Agency to the intermediary lender will bear interest at a fixed rate as determined by the Administrator, but not less than 1 percent per year over the term of the loan.
(1) Interest rates charged by intermediary lender to ultimate recipients on loans from the HFIL revolving fund will be negotiated between the intermediary lender and ultimate recipient, but the rate must be within limits established by the Intermediary Relending Agreement.
(2) The rate should normally be the lowest rate sufficient to cover the loan's proportional share of the revolving fund's debt service costs and administrative costs.
(b) No loan to an intermediary lender will be extended for a period exceeding 30 years. Interest will be due annually but principal payments may be deferred by the Agency.
(1) Loans made by an intermediary lender to an ultimate recipient from the HFIL revolving fund will be scheduled for repayment over a term negotiated by the intermediary lender and ultimate recipient but will not exceed 30 years or the date of the end of the term of the HFIL loan, whichever is sooner.
(2) The term of an HFIL loan must be reasonable and prudent considering the purpose of the loan, expected repayment ability of the ultimate recipient, and the useful life of collateral, and must be within any limits established by the intermediary lender's Intermediary Relending Agreement.
(a)
(1) Assignments of assessments, taxes, levies, or other sources of revenue as authorized by law;
(2) Investments and deposits of the intermediary; and
(3) Capital assets or other property of the intermediary and its members.
(b)
(c)
(1) The Agency will only require concurrence in the intermediary lender's security requirement for a specific loan when security for the loan from the intermediary lender to the ultimate recipient will also serve as security for an Agency loan.
(2) The ultimate recipient will take appropriate action to obtain and provide security for the loan.
(a) The application will consist of:
(1) An application form provided by the Agency;
(2) A draft Intermediary Relending Agreement and other evidence the Agency requires to show the feasibility of the intermediary lender's program to meet the objectives of the HFIL Loan Program; and
(3) Applications from intermediary lenders that already have an active HFIL loan may be streamlined by filing a new application and a statement that the new loan would be operated in accordance with the Intermediary Relending Agreement on file for the previous loan. This statement may be submitted at the time of application in lieu of a new Intermediary Relending Agreement.
(4) Documentation of the intermediary lender's ability to administer HFIL in accordance with this part;
(5) Submission of a completed Agency application form;
(6) Prior to approval of a loan or advance of funds, certification of whether or not the intermediary lender is delinquent on any Federal debt, including, but not limited to, Federal income tax obligations or a loan or loan guarantee or from another Federal agency. If delinquent, the intermediate lender must explain the reasons for the delinquency, and the Agency will take such written explanation into consideration in deciding whether to approve the loan or advance of funds;
(7) Prior to approval of a loan or advance of funds, certification as to whether the intermediary lender has been convicted of a felony criminal violation under Federal law in the 24 months preceding the date of application.
(8) Certification of compliance with the restrictions and requirements in 31 U.S.C. 1352, and 2 CFR 200.450 and part 418.
(9) Certification to having been informed of the collection options the Federal government may use to collect delinquent debt.
(b) An intermediary lender that has received one or more HFIL loans may apply for and be considered for subsequent HFIL loans provided:
(1) The intermediary lender is relending all collections from loans made from its revolving fund in excess of what is needed for required debt service, approved administration costs, and a reserve for debt service;
(2) The outstanding loans of the intermediary lender's HFIL revolving fund are performing; and
(3) The intermediary lender is in compliance with all regulations and its loan agreements with the Agency.
(a) The Agency will provide the intermediary lender a letter listing all requirements for the loan. After reviewing the conditions and requirements in the letter of conditions, the intermediary lender must complete, sign, and return the form provided by the Agency indicating the intermediary lender's intent to meet the conditions. If certain conditions cannot be met, the intermediary lender may propose alternate conditions in writing to the
(b) At loan closing, the intermediary lender must certify that:
(1) No major changes have been made in the Intermediary Relending Agreement except those approved in the interim by the Agency;
(2) All requirements of the letter of conditions have been met; and
(3) There has been no material change in the intermediary lender or its financial condition since the issuance of the letter of conditions. If there have been changes, the intermediary lender must explain the changes to the Agency. The changes may be waived, at the sole discretion of the Agency.
(a) Loan requests will be processed based on the date the Agency receives the application. Loan approval is subject to the availability of funds.
(b) The loan will be considered approved for the intermediary lender on the date the signed copy of the obligation of funds document is mailed to the intermediary lender.
(a)
(1) The amount of the loan, the interest rate, the term and repayment schedule,
(2) The requirement to maintain a separate ledger and segregated account for the HFIL revolving fund; and
(3) It agrees to comply with Agency reporting requirements.
(b)
(c)
(1) The proposed ultimate recipient is eligible for the loan;
(2) The proposed loan is for eligible purposes; and
(3) The proposed loan complies with all applicable laws and regulations.
(a)
(1) The portion of the HFIL revolving fund that consists of Agency HFIL loan funds may only be used for making loans in accordance with § 769.105. The portion of the HFIL revolving fund that consists of repayments from ultimate recipients may be used for debt service, reasonable administrative costs, or for making additional loans;
(2) An intermediary lender may use revolving funds and HFIL loan funds to make loans to ultimate recipients without obtaining prior Agency concurrence in accordance with the Intermediary Relending Agreement;
(3) Any funds in the HFIL revolving fund from any source that is not needed for debt service, approved administrative costs, or reasonable reserves must be available for additional loans to ultimate recipients;
(4) All reserves and other funds in the HFIL revolving loan fund not immediately needed for loans to ultimate recipients or other authorized uses must be deposited in accounts in banks or other financial institutions. Such accounts must be fully covered by Federal deposit insurance or fully collateralized with U.S. Government obligations, and will be interest bearing. Any interest earned thereon remains a part of the HFIL revolving fund;
(5) If an intermediary lender receives more than one HFIL loan, it does not need to establish and maintain a separate HFIL revolving loan fund for each loan; it may combine them and maintain only one HFIL revolving fund, unless the Agency requires separate HFIL revolving funds because there are significant differences in the loan purposes, Intermediary Relending Agreement, loan agreements, or requirements for the loans; and
(6) A reasonable amount of revolved funds must be used to create a reserve for bad debts. Reserves should be accumulated over a period of years. The total amount should not exceed maximum expected losses, considering the quality of the intermediary lender's portfolio of loans. Unless the intermediary lender provides loss and delinquency records that, in the opinion of the Agency, justifies different amounts, a reserve for bad debts of 6 percent of outstanding loans must be accumulated over 5 years and then maintained.
(b)
(1) At least annually, the intermediary lender must provide the Agency documents for the purpose of reviewing the financial status of the intermediary Lender, assessing the progress of utilizing loan funds, and identifying any potential problems or concerns. Non-regulated intermediary lenders must furnish audited financial statements at least annually.
(2) At any time the Agency determines it is necessary, the intermediary lender must allow the Agency or its representative to review the operations and financial condition of the intermediary lender. Upon the Agency requests, the Intermediary must submit financial or other information within 14 days unless the data requested is not available within that time frame.
(c)
(a)
(b)
(1) The Government's interest will be protected;
(2) The restructuring will be performed within the Agency's budget authority; and
(3) The loan objectives cannot be met unless the HFIL loan is restructured.
(c)
(a) All transfers and assumptions must be approved in advance in writing by the Agency. The assuming entity must meet all eligibility criteria for the HFIL Loan Program.
(b) Available transfer and assumption options to eligible intermediary lenders include the following:
(1) The total indebtedness may be transferred to another eligible intermediary lender on the same terms; or
(2) The total indebtedness may be transferred to another eligible intermediary lender on different terms not to exceed the term for which an initial loan can be made. The assuming entity must meet all eligibility criteria for the HFIL Loan Program.
(c) The transferor must prepare the transfer document for the Agency review prior to the transfer and assumption.
(d) The transferee must provide the Agency with information required in the application as specified in § 769.109.
(e) The Agency prepared assumption agreement will contain the Agency case number of the transferor and transferee.
(f) The transferee must complete an application as specified in § 769.109(a).
(g) When the transferee makes a cash down-payment in connection with the transfer and assumption, any proceeds received by the transferor will be credited on the transferor's loan debt in order of maturity date.
(h) The Administrator or designee will approve or decline all transfers and assumptions.
Any appealable adverse decision made by the Agency may be appealed upon written request of the intermediary as specified in 7 CFR part 11.
The Agency may grant an exception to any of the requirements of this part if the proposed change is in the best financial interest of the Government and not inconsistent with the authorizing law or any other applicable law.
Nuclear Regulatory Commission.
Final rule.
The U.S. Nuclear Regulatory Commission (NRC) is amending its regulations to make miscellaneous corrections. These changes include renaming the Office of Information Services, renaming the Computer Security Office and removing it as a standalone office, capitalizing the words Tribe, Tribes, and Tribal, correcting a Web site address, correcting a misspelling, removing a submission requirement, correcting an email address, correcting a room number, removing a
This rule is effective December 31, 2015.
Please refer to Docket ID NRC-2015-0239 when contacting the NRC about the availability of information for this final rule. You may obtain publicly-available information related to this final rule by any of the following methods:
•
•
You may obtain publicly-available documents online in the ADAMS Public Documents collection at
•
Jill Shepherd-Vladimir, Office of Administration, telephone: 301-415-1230, email:
The NRC is amending its regulations in parts 1, 2, 4, 7, 9, 11, 15, 19, 20, 21, 25, 26, 30, 32, 37, 40, 50, 51, 52, 55, 60, 61, 62, 63, 70, 71, 72, 73, 74, 76, 81, 95, 100, 110, 140, 150, 170, and 171 of title 10 of the
Remove
Under the Administrative Procedure Act (5 U.S.C. 553(b)), an agency may waive the normal notice and comment requirements if it finds, for good cause, that they are impracticable, unnecessary, or contrary to the public interest. As authorized by 5 U.S.C. 553(b)(3)(B), the NRC finds good cause to waive notice and opportunity for comment on the amendments, because notice and opportunity for comment are unnecessary. The amendments will have no substantive impact and are of a minor and administrative nature dealing with corrections to certain CFRs related only to management, organization, procedure, and practice. Specifically, the revisions rename offices, capitalize words, correct a Web site address, correct a misspelling, remove a submission requirement, correct an email address, correct a room number, remove a
The Commission is exercising its authority under 5 U.S.C. 553(b)(3)(B) to publish these amendments as a final rule. The amendments are effective December 31, 2015. These amendments do not require action by any person or entity regulated by the NRC. Also, the final rule does not change the substantive responsibilities of any person or entity regulated by the NRC.
The NRC has determined that this final rule is the type of action described in 10 CFR 51.22(c)(2), which categorically excludes from environmental review rules that are corrective or of a minor, nonpolicy nature and do not substantially modify existing regulations. Therefore, neither an environmental impact statement nor an environmental assessment has been prepared for this rule.
This final rule does not contain a collection of information as defined in the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
The NRC may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the requesting document displays a currently valid Office of Management and Budget control number.
The Plain Writing Act of 2010 (Pub. L. 111-274) requires Federal agencies to
The NRC has determined that the corrections in this final rule do not constitute backfitting and are not inconsistent with any of the issue finality provisions in 10 CFR part 52. The revisions are non-substantive in nature, including renaming offices, capitalizing words, correcting a Web site address, correcting a misspelling, removing a submission requirement, correcting an email address, correcting a room number, removing a
Flags, Organization and functions (Government Agencies), Seals and insignia.
Administrative practice and procedure, Antitrust, Byproduct material, Classified information, Confidential business information, Freedom of information, Environmental protection, Hazardous waste, Nuclear energy, Nuclear materials, Nuclear power plants and reactors, Penalties, Reporting and recordkeeping requirements, Sex discrimination, Source material, Special nuclear material, Waste treatment and disposal.
Administrative practice and procedure, Aged, Blind, Buildings, Civil rights, Employment, Equal employment opportunity, Federal aid programs, Federal buildings and facilities, Grant programs, Handicapped, Individuals with disabilities, Loan programs, Reporting and recordkeeping requirements, Sex discrimination.
Advisory committees, Sunshine Act.
Administrative practice and procedure, Courts, Criminal penalties, Freedom of information, Government employees, Privacy, Reporting and recordkeeping requirements, Sunshine Act.
Hazardous materials transportation, Investigations, Nuclear energy, Nuclear materials, Penalties, Reporting and recordkeeping requirements, Security measures, Special nuclear material.
Administrative practice and procedure, Claims, Debt collection.
Criminal penalties, Environmental protection, Nuclear Energy, Nuclear materials, Nuclear power plants and reactors, Occupational safety and health, Penalties, Radiation protection, Reporting and recordkeeping requirements, Sex discrimination.
Byproduct material, Criminal penalties, Hazardous waste, Licensed material, Nuclear energy, Nuclear materials, Nuclear power plants and reactors, Occupational safety and health, Packaging and containers, Penalties, Radiation protection, Reporting and recordkeeping requirements, Source material, Special nuclear material, Waste treatment and disposal.
Nuclear power plants and reactors, Penalties, Radiation protection, Reporting and recordkeeping requirements.
Classified information, Criminal penalties, Investigations, Penalties, Reporting and recordkeeping requirements, Security measures.
Administrative practice and procedure, Alcohol abuse, Alcohol testing, Appeals, Chemical testing, Drug abuse, Drug testing, Employee assistance programs, Fitness for duty, Management actions, Nuclear power plants and reactors, Privacy, Protection of information, Radiation protection, Reporting and recordkeeping requirements.
Byproduct material, Criminal penalties, Government contracts, Intergovernmental relations, Isotopes, Nuclear energy, Nuclear materials, Penalties, Radiation protection, Reporting and recordkeeping requirements, Whistleblowing.
Byproduct material, Criminal penalties, Labeling, Nuclear energy, Nuclear materials, Radiation protection, Reporting and recordkeeping requirements.
Byproduct material, Criminal penalties, Export, Hazardous materials transportation, Import, Licensed material, Nuclear materials, Penalties, Radioactive materials, Reporting and recordkeeping requirements, Security measures.
Criminal penalties, Exports, Government contracts, Hazardous materials transportation, Hazardous waste, Nuclear energy, Nuclear materials, Penalties, Reporting and recordkeeping requirements, Source material, Uranium, Whistleblowing.
Administrative practice and procedure, Antitrust, Classified information, Criminal penalties, education, Fire prevention, Fire protection, Incorporation by reference, Intergovernmental relations, Nuclear power plants and reactors, Penalties, Radiation protection, Reactor siting criteria, Reporting and recordkeeping requirements, Whistleblowing.
Administrative practice and procedure, Environmental impact statements, Hazardous waste, Nuclear energy, Nuclear materials, Nuclear power plants and reactors, Reporting and recordkeeping requirements.
Administrative practice and procedure, Antitrust, Backfitting, Combined license, Early site permit, Emergency planning, Fees, Incorporation by reference, Inspection, Limited work authorization, Nuclear power plants and reactors, Probabilistic risk assessment, Prototype, Reactor siting criteria, Redress of site, Penalties, Reporting and recordkeeping requirements, Standard design, Standard design certification.
Criminal penalties, Manpower training programs, Nuclear power plants and reactors, Reporting and recordkeeping requirements.
Criminal penalties, Hazardous waste, Indians, High-level waste, Intergovernmental relations, Nuclear energy, Nuclear materials, Nuclear power plants and reactors, Penalties, Radiation protection, Reporting and recordkeeping requirements, Waste treatment and disposal, Whistleblowing.
Criminal penalties, Hazardous waste, Indians, Intergovernmental relations, Low-level waste, Nuclear energy, Nuclear materials, Penalties, Reporting and recordkeeping requirements, Waste treatment and disposal, Whistleblowing.
Administrative practice and procedure, Denial of access, Emergency access to low-level waste disposal, Hazardous waste, Intergovernmental relations, Low-level radioactive waste, Low-level radioactive waste treatment and disposal, Nuclear energy, Nuclear materials, Radiation protection, Reporting and recordkeeping requirements.
Criminal penalties, Hazardous waste, High-level waste, Indians, Intergovernmental relations, Nuclear energy, Nuclear power plants and reactors, Penalties, Radiation protection, Reporting and recordkeeping requirements, Waste treatment and disposal.
Classified information, Criminal penalties, Emergency medical services, Hazardous materials transportation, Material control and accounting, Nuclear energy, Nuclear materials, Packaging and containers, Penalties, Radiation protection, Reporting and recordkeeping requirements, Scientific equipment, Security measures, Special nuclear material, Whistleblowing.
Criminal penalties, Hazardous materials transportation, Incorporation by reference, Intergovernmental relations, Nuclear materials, Packaging and containers, Penalties, Radioactive materials, Reporting and recordkeeping requirements.
Administrative practice and procedure, Criminal penalties, Hazardous waste, Indians, Intergovernmental relations, Manpower training programs, Nuclear energy, Nuclear materials, Occupational safety and health, Penalties, Radiation protection, Reporting and recordkeeping requirements, Security measures, Spent fuel, Whistleblowing.
Criminal penalties, Exports, Hazardous materials transportation, Incorporation by reference, Imports, Nuclear energy, Nuclear materials, Nuclear power plants and reactors, Penalties, Reporting and recordkeeping requirements, Security measures.
Accounting, Criminal penalties, Hazardous materials transportation, Material control and accounting, Nuclear energy, Nuclear materials, Packaging and containers, Penalties, Radiation protection, Reporting and recordkeeping requirements, Scientific equipment, Special nuclear material.
Certification, Criminal penalties, Nuclear energy, Penalties, Radiation protection, Reporting and record keeping requirements, Security measures, Special nuclear material, Uranium, Uranium enrichment by gaseous diffusion.
Administrative practice and procedure, Inventions and patents, Reporting and recordkeeping requirements.
Classified information, Criminal penalties, Penalties, Reporting and recordkeeping requirements, Security measures.
Nuclear power plants and reactors, Radiation protection, Reactor siting criteria, Reporting and recordkeeping requirements.
Administrative practice and procedure, Classified information, Criminal penalties, Exports, Incorporation by reference, Imports, Intergovernmental relations, Nuclear energy, Nuclear materials, Nuclear power plants and reactors, Penalties, Reporting and recordkeeping requirements, Scientific equipment.
Criminal penalties, Extraordinary nuclear occurrence, Insurance, Intergovernmental relations, Nuclear materials, Nuclear power plants and reactors, Penalties, Reporting and recordkeeping requirements.
Criminal penalties, Hazardous materials transportation, Intergovernmental relations, Nuclear energy, Nuclear materials, Penalties, Reporting and recordkeeping requirements, Security measures, Source material, Special nuclear material.
Byproduct material, Import and export licenses, Intergovernmental relations, Non-payment penalties, Nuclear energy, Nuclear materials, Nuclear power plants and reactors, Source material, Special nuclear material.
Annual charges, Byproduct material, Holders of certificates, registrations, approvals, Intergovernmental relations, Nonpayment penalties, Nuclear materials, Nuclear power plants and reactors, Source material, Special nuclear material.
For the reasons set out in the preamble and under the authority of the Atomic Energy Act of 1954, as amended; the Energy Reorganization Act of 1974, as amended; and 5 U.S.C. 552 and 553, the NRC is adopting the following amendments to 10 CFR parts 1, 2, 4, 7, 9, 11, 15, 19, 20, 21, 25, 26, 30, 32, 37, 40, 50, 51, 52, 55, 60, 61, 62, 63, 70, 71, 72, 73, 74, 76, 81, 95, 100, 110, 140, 150, 170, and 171:
Atomic Energy Act of 1954, secs. 23, 25, 29, 161, 191 (42 U.S.C. 2033, 2035, 2039, 2201, 2241); Energy Reorganization Act of 1974, secs. 201, 203, 204, 205, 209 (42 U.S.C. 5841, 5843, 5844, 5845, 5849); Administrative Procedure Act (5 U.S.C. 552, 553); Reorganization Plan No. 1 of 1980, 5 U.S.C. Appendix (Reorganization Plans).
The revision and additions read as follows:
The Office of the Chief Information Officer—
(h) Plans, recommends, and oversees the NRC's Information Technology (IT) Security Program consistent with applicable laws, regulations, management initiatives, and policies;
(i) Provides principal advice to the NRC on the infrastructure, as well as the programmatic and administrative aspects of cybersecurity;
(j) Establishes NRC-wide cybersecurity guidelines;
(k) Guides security process maturity, as well as formulating and overseeing the cybersecurity program budget; and
(l) Ensures NRC-wide integration, direction, and coordination of IT security planning and performance within the framework of the NRC IT Security Program.
Atomic Energy Act of 1954, secs. 29, 53, 62, 63, 81, 102, 103, 104, 105, 161, 181, 182, 183, 184, 186, 189, 191, 234 (42 U.S.C. 2039, 2073, 2092, 2093, 2111, 2132, 2133, 2134, 2135, 2201, 2231, 2232, 2233, 2234, 2236, 2239, 2241, 2282); Energy Reorganization Act of 1974, secs. 201, 206 (42 U.S.C. 5841, 5846); Nuclear Waste Policy Act of 1982, secs. 114(f), 134, 135, 141 (42 U.S.C. 10134(f), 10154, 10155, 10161); Administrative Procedure Act (5 U.S.C. 552, 553); National Environmental Policy Act of 1969 (42 U.S.C. 4332); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 161, 223, 234, 274 (42 U.S.C. 2201, 2273, 2282, 2021); Energy Reorganization Act of 1974, secs. 201, 401 (42 U.S.C. 5841, 5891); 29 U.S.C. 794; 42 U.S.C. 12101
Subpart A also issued under 42 U.S.C. 2000d through d-7.
Subpart B also issued under 29 U.S.C. 706.
Subpart C also issued under 42 U.S.C. 6101 through 6107.
Atomic Energy Act of 1954, sec. 161 (42 U.S.C. 2201); Energy Reorganization Act of 1974, sec. 201 (42 U.S.C. 5841); 5 U.S.C. Appendix (Federal Advisory Committee Act).
Atomic Energy Act of 1954, sec. 161 (42 U.S.C. 2201); Energy Reorganization Act of 1974, sec. 201 (42 U.S.C. 5841); 44 U.S.C. 3504 note.
Subpart A also issued under 31 U.S.C. 9701.
Subpart B also issued under 5 U.S.C. 552a.
Subpart C also issued under 5 U.S.C. 552b.
Atomic Energy Act of 1954, secs. 161, 223 (42 U.S.C. 2201, 2273); Energy Reorganization Act of 1974, sec. 201 (42 U.S.C. 5841); 44 U.S.C. 3504 note.
Section 11.15(e) also issued under 31 U.S.C. 9701; 42 U.S.C. 2214.
Atomic Energy Act of 1954, sec. 161, 186 (42 U.S.C. 2201, 2236); Energy Reorganization Act of 1974, sec. 201 (42 U.S.C. 5841); 5 U.S.C. 5514; 26 U.S.C. 6402; 31 U.S.C. 3701, 3713, 3716, 3719, 3720A; 42 U.S.C. 664; 44 U.S.C. 3504 note; 31 CFR parts 900 through 904; 31 CFR part 285; E.O. 12146, 44 FR 42657, 3 CFR, 1979 Comp., p. 409; E.O. 12988, 61 FR 4729, 3 CFR, 1996 Comp., p.157.
Atomic Energy Act of 1954, secs. 53, 63, 81, 103, 104, 161, 223, 234, 1701 (42 U.S.C. 2073, 2093, 2111, 2133, 2134, 2201, 2273, 2282, 2297f); Energy Reorganization Act of 1974, secs. 201, 211, 401 (42 U.S.C. 5841, 5851, 5891); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 11, 53, 63, 65, 81, 103, 104, 161, 170H, 182, 186, 223, 234, 274, 1701 (42 U.S.C. 2014, 2073, 2093, 2095, 2111, 2133, 2134, 2201, 2210h, 2232, 2236, 2273, 2282, 2021, 2297f); Energy Reorganization Act of 1974, secs. 201, 202 (42 U.S.C. 5841, 5842); Low-Level Radioactive Waste Policy Amendments Act of 1985, sec. 2 (42 U.S.C. 2021b); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 53, 63, 81, 103, 104, 161, 223, 234, 1701 (42 U.S.C. 2073, 2093, 2111, 2133, 2134, 2201, 2273, 2282, 2297f); Energy Reorganization Act of 1974, secs. 201, 206 (42 U.S.C. 5841, 5846); Nuclear Waste Policy Act of 1982,, secs. 135, 141 (42 U.S.C. 10155, 10161); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 145, 161, 223, 234 (42 U.S.C. 2165, 2201, 2273, 2282); Energy Reorganization Act of 1974, sec. 201 (42 U.S.C. 5841); 44 U.S.C. 3504 note; E.O. 10865, 25 FR 1583, as amended, 3 CFR, 1959-1963 Comp., p. 398; E.O. 12829, 58 FR 3479, 3 CFR, 1993 Comp., p. 570; E.O. 13526, 75 FR 707, 3 CFR, 2009 Comp., 9.298; E.O. 12968, 60 FR 40245, 3 CFR, 1995 Comp., p. 391.
Section 25.17(f) and Appendix A also issued under 31 U.S.C. 9701; 42 U.S.C. 2214.
Atomic Energy Act of 1954, secs. 53, 103, 104, 107, 161, 223, 234, 1701 (42 U.S.C. 2073, 2133, 2134, 2137, 2201, 2273, 2282, 2297f); Energy Reorganization Act of 1974, secs. 201, 202 (42 U.S.C. 5841, 5842); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 11, 81, 161, 181, 182, 183, 184, 186, 187, 223, 234, 274 (42 U.S.C. 2014, 2111, 2201, 2231, 2232, 2233, 2234, 2236, 2237, 2273, 2282, 2021); Energy Reorganization Act of 1974, secs. 201, 202, 206, 211 (42 U.S.C. 5841, 5842, 5846, 5851); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 81, 161, 170H, 181, 182, 183, 223, 234, 274 (42 U.S.C. 2111, 2201, 2210h, 2231, 2232, 2233, 2273, 2282, 2021); Energy Reorganization Act of 1974, sec. 201 (42 U.S.C. 5841); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 11, 53, 81, 103, 104, 147, 148, 149, 161, 182, 183, 223, 234, 274 (42 U.S.C. 2014, 2073, 2111, 2133, 2134, 2167, 2168, 2169, 2201, 2232, 2233, 2273, 2282, 2021); Energy Reorganization Act of 1974, secs. 201, 202 (42 U.S.C. 5841, 5842); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 62, 63, 64, 65, 69, 81, 83, 84, 122, 161, 181, 182, 183, 184, 186, 193, 223, 234, 274, 275 (42 U.S.C. 2092, 2093, 2094, 2095, 2099, 2111, 2113, 2114, 2152, 2201, 2231, 2232, 2233, 2234, 2236,2237, 2243, 2273, 2282, 2021, 2022); Energy Reorganization Act of 1974, secs. 201, 202, 206, 211 (42 U.S.C. 5841, 5842, 5846, 5851); Uranium Mill Tailings Radiation Control Act of 1978, sec. 104 (42 U.S.C. 7914); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 11, 101, 102, 103, 104, 105, 108, 122, 147, 149, 161, 181, 182, 183, 184, 185, 186, 187, 189, 223, 234 (42 U.S.C. 2014, 2131, 2132, 2133, 2134, 2135, 2138, 2152, 2167, 2169, 2201, 2231, 2232, 2233, 2234, 2235, 2236, 2237, 2239, 2273, 2282); Energy Reorganization Act of 1974, secs. 201, 202, 206, 211 (42 U.S.C. 5841, 5842, 5846, 5851); Nuclear Waste Policy Act of 1982, sec. 306 (42 U.S.C. 10226); National Environmental Policy Act of 1969 (42 U.S.C. 4332); 44 U.S.C. 3504 note; Sec. 109, Pub. L. 96-295, 94 Stat. 783.
No less than 180 days before the scheduled issuance of an operating license for a nuclear power reactor or a license to possess nuclear material, or the scheduled date for initial loading of fuel for a combined license under part 52 of this chapter, the applicant's or licensee's detailed implementing procedures for its emergency plan shall be submitted to the Commission as specified in § 50.4.
Atomic Energy Act of 1954, secs. 161, 193 (42 U.S.C. 2201, 2243); Energy Reorganization Act of 1974, secs. 201, 202 (42 U.S.C. 5841, 5842); National Environmental Policy Act of 1969 (42 U.S.C. 4332, 4334, 4335); Nuclear Waste Policy Act of 1982, secs. 144(f), 121, 135, 141, 148 (42 U.S.C. 10134(f), 10141, 10155, 10161, 10168); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 103, 104, 147, 149, 161, 181, 182, 183, 185, 186, 189, 223, 234 (42 U.S.C. 2133, 2134, 2167, 2169, 2201, 2231, 2232, 2233, 2235, 2236, 2239, 2273, 2282); Energy Reorganization Act of 1974, secs. 201, 202, 206, 211 (42 U.S.C. 5841, 5842, 5846, 5851); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 107, 161, 181, 182, 183, 186, 187, 223, 234 (42 U.S.C. 2137, 2201, 2231, 2232, 2233, 2236, 2237, 2273, 2282); Energy Reorganization Act secs. 201, 202 (42 U.S.C. 5841, 5842); Nuclear Waste Policy Act of 1982, sec. 306 (42 U.S.C. 10226); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 51, 53, 62, 63, 65, 81, 161, 182, 183, 223, 234 (42 U.S.C. 2071, 2073, 2092, 2093, 2095, 2111, 2201, 2232, 2233, 2273, 2282); Energy Reorganization Act of 1974, secs. 201, 202, 206, 211 (42 U.S.C. 5841, 5842, 5846, 5851); 42 U.S.C. 2021a; National Environmental Policy Act of 1969 (42 U.S.C. 4332); Nuclear Waste Policy Act of 1982, secs. 114, 117, 121 (42 U.S.C. 10134, 10137, 10141); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 53, 57, 62, 63, 65, 81, 161, 181, 182, 183, 223, 234 (42 U.S.C. 2073, 2077, 2092, 2093, 2095, 2111, 2201, 2231, 2232, 2233, 2273, 2282); Energy Reorganization Act of 1974, secs. 201, 206, 211 (42 U.S.C. 5841, 5846, 5851); Low-Level Radioactive Waste Policy Amendments Act of 1985, sec. 2 (42 U.S.C.2021b); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, sec. 161 (42 U.S.C. 2201); Energy Reorganization Act of 1974, sec. 201 (42 U.S.C. 5841); Low-Level Radioactive Waste Policy Act of 1985, secs. 2, 6 (42 U.S.C. 2021b, 2021f); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 51, 53, 62, 63, 65, 81, 161, 182, 183, 223, 234 (42 U.S.C. 2071, 2073, 2092, 2093, 2095, 2111, 2201, 2232, 2233, 2273, 2282); Energy Reorganization Act of 1974, secs. 201, 202, 206, 211 (42 U.S.C. 5841, 5842, 5846, 5851); 42 U.S.C. 2021a; National Environmental Policy Act of 1969 (42 U.S.C. 4332); Nuclear Waste Policy Act of 1982, secs. 114, 117, 121 (42 U.S.C. 10134, 10137, 10141); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 51, 53, 57(d), 108, 122, 161, 182, 183, 184, 186, 187, 193, 223, 234, 274, 1701 (42 U.S.C. 2071, 2073, 2077(d), 2138, 2152, 2201, 2232, 2233, 2234, 2236, 2237, 2243, 2273, 2282, 2021, 2297f); Energy Reorganization Act of 1974, secs. 201, 202, 206, 211 (42 U.S.C. 5841, 5842, 5846, 5851); Nuclear Waste Policy Act of 1982, secs. 135, 141 (42 U.S.C. 10155, 10161); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 53, 57, 62, 63, 81, 161, 182, 183, 223, 234, 1701 (42 U.S.C. 2073, 2077, 2092, 2093, 2111, 2201, 2232, 2233, 2273, 2282, 2297f); Energy Reorganization Act of 1974, secs. 201, 202, 206, 211 (42 U.S.C. 5841, 5842, 5846, 5851); Nuclear Waste Policy Act of 1982, sec. 180 (42 U.S.C. 10175); 44 U.S.C. 3504 note.
Section 71.97 also issued under Sec. 301, Pub. L. 96-295, 94 Stat. 789 (42 U.S.C. 5841 note).
(c) * * *
(3) * * *
(ii) Contact information for each State, including telephone and mailing addresses of governors and governors' designees, and participating Tribes, including telephone and mailing addresses of Tribal officials and Tribal official's designees, is available on the NRC Web site at:
Atomic Energy Act of 1954, secs. 51, 53, 57, 62, 63, 65, 69, 81, 161, 182, 183, 184, 186, 187, 189, 223, 234, 274 (42 U.S.C. 2071, 2073, 2077, 2092, 2093, 2095, 2099, 2111, 2201, 2210e, 2232, 2233, 2234, 2236, 2237, 2238, 2273, 2282, 2021); Energy Reorganization Act of 1974, secs. 201, 202, 206, 211 (42 U.S.C. 5841, 5842, 5846, 5851); National Environmental Policy Act of 1969 (42 U.S.C. 4332); Nuclear Waste Policy Act of 1982, secs. 117(a), 132, 133, 134, 135, 137, 141, 145(g), 148, 218(a) (42 U.S.C. 10137(a), 10152, 10153, 10154, 10155, 10157, 10161, 10165(g), 10168, 10198(a)); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 53, 147, 149, 161, 170D, 170E, 170H, 170I, 223, 229, 234, 1701 (42 U.S.C. 2073, 2167, 2169, 2201, 2210d, 2210e, 2210h, 2210i, 2273, 2278a, 2282, 2297f); Energy Reorganization Act of 1974, secs. 201, 202 (42 U.S.C. 5841, 5842); Nuclear Waste Policy Act of 1982, secs. 135, 141 (42 U.S.C. 10155, 10161); 44 U.S.C. 3504 note.
Section 73.37(b)(2) also issued under Sec. 301, Pub. L. 96-295, 94 Stat. 789 (42 U.S.C. 5841 note).
(b) The approved information collection requirements contained in this part appear in §§ 73.5, 73.20, 73.21, 73.23, 73.24, 73.25, 73.26, 73.27, 73.37, 73.38, 73.40, 73.45, 73.46, 73.50, 73.51, 73.54, 73.55, 73.56, 73.57, 73.58, 73.60, 73.67, 73.70, 73.71, 73.72, 73.73, 73.74, and appendices B, C, and G to this part.
Atomic Energy Act of 1954, secs. 53, 57, 161, 182, 183, 223, 234, 1701 (42 U.S.C. 2073, 2077, 2201, 2232, 2273, 2282, 2297f); Energy Reorganization Act of 1974, secs. 201, 202 (42 U.S.C. 5841, 5842); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 122, 161, 193(f), 223, 234, 1701 (42 U.S.C. 2152, 2201, 2243(f), 2273, 2282, 2297f); Energy Reorganization Act of 1974, secs. 201, 206, 211 (42 U.S.C. 5841, 5846, 5851); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 156, 161 (42 U.S.C. 2186, 2201); Energy Reorganization Act of 1974, sec. 201 (42 U.S.C. 5841); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 145, 161, 223, 234 (42 U.S.C. 2165, 2201, 2273, 2282); Energy Reorganization Act of 1974, sec. 201 (42 U.S.C. 5841); 44 U.S.C. 3504 note; E.O. 10865, as amended, 25 FR 1583, 3 CFR, 1959-1963 Comp., p. 398; E.O. 12829, 58 FR 3479, 3 CFR, 1993 Comp., p. 570; E.O. 12968, 60 FR 40245, 3 CFR, 1995 Comp., p. 391; E.O. 13526, 75 FR 707, 3 CFR, 2009 Comp., p. 298.
Atomic Energy Act of 1954, secs. 103, 104, 161, 182 (42 U.S.C. 2133, 2134, 2201, 2232); Energy Reorganization Act of 1974, secs. 201, 202 (42 U.S.C. 5841, 5842); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 11, 51, 53, 54, 57, 62, 63, 64, 65, 81, 82, 103, 104, 109, 111, 121, 122, 123, 124, 126, 127, 128, 129, 133, 134, 161, 170H, 181, 182, 183, 184, 186, 187, 189, 223, 234 (42 U.S.C. 2014, 2071, 2073, 2074, 2077, 2092, 2093, 2094, 2095, 2111, 2112, 2133, 2134, 2139, 2141, 2151, 2152, 2153, 2154, 2155, 2156, 2157, 2158, 2160c, 216d, 2201, 2210h, 2231, 2232, 2233, 2234, 2236, 2237, 2239, 2273, 2282); Energy Reorganization Act of 1974, sec. 201 (42 U.S.C. 5841); Administrative Procedure Act (5 U.S.C. 552, 553); 42 U.S.C. 2139a, 2155a; 44 U.S.C. 3504 note.
Section 110.1(b) also issued under 22 U.S.C. 2403; 22 U.S.C. 2778a; 50 App. U.S.C. 2401
Atomic Energy Act of 1954, secs. 161, 170, 223, 234 (42 U.S.C. 2201, 2210, 2273, 2282); Energy Reorganization Act of 1974, secs. 201, 202 (42 U.S.C. 5841, 5842); 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 11, 53, 81, 83, 84, 122, 161, 181, 223, 234, 274 (42 U.S.C. 2014, 2201, 2231, 2273, 2282, 2021); Energy Reorganization Act of 1974, sec. 201 (42 U.S.C. 5841); Nuclear Waste Policy Act of 1982, secs. 135, 141 (42 U.S.C. 10155, 10161; 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 11, 161(w) (42 U.S.C. 2014, 2201(w)); Energy Reorganization Act of 1974, sec. 201 (42 U.S.C. 5841); 42 U.S.C. 2214; 31 U.S.C. 901, 902, 9701; 44 U.S.C. 3504 note.
Atomic Energy Act of 1954, secs. 11, 161(w), 223, 234 (42 U.S.C. 2014, 2201(w), 2273, 2282); Energy Reorganization Act of 1974, sec. 201 (42 U.S.C. 5841); 42 U.S.C. 2214; 44 U.S.C. 3504 note.
For the Nuclear Regulatory Commission.
Federal Aviation Administration (FAA), Department of Transportation (DOT).
Final rule; request for comments.
We are publishing a new airworthiness directive (AD) for Airbus Helicopters Model AS350B3 helicopters. This AD was sent previously to all known U.S. owners and operators of these helicopters and supersedes Emergency AD 2015-22-52, dated October 28, 2015. This AD requires revising the rotorcraft flight manual (RFM) to stop performing the yaw load compensator check during preflight procedures and instead perform it during post-flight procedures after rotor shut-down. This AD also requires the yaw servo hydraulic switch
This AD becomes effective December 16, 2015 to all persons except those persons to whom it was made immediately effective by Emergency AD 2015-22-53, issued on October 30, 2015, which contains the requirements of this AD.
We must receive comments on this AD by February 1, 2016.
You may send comments by any of the following methods:
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You may examine the AD docket on the Internet at
For service information identified in this AD, contact Airbus Helicopters, 2701 N. Forum Drive, Grand Prairie, TX 75052; telephone (972) 641-0000 or (800) 232-0323; fax (972) 641-3775; or at
Stephen Barbini, Flight Test Engineer, Regulations and Policy Group, Rotorcraft Directorate, FAA, 10101 Hillwood Pkwy, Fort Worth, TX 76177; telephone (817) 222-5110; email
This AD is a final rule that involves requirements affecting flight safety, and we did not provide you with notice and an opportunity to provide your comments prior to it becoming effective. However, we invite you to participate in this rulemaking by submitting written comments, data, or views. We also invite comments relating to the economic, environmental, energy, or federalism impacts that resulted from adopting this AD. The most helpful comments reference a specific portion of the AD, explain the reason for any recommended change, and include supporting data. To ensure the docket does not contain duplicate comments, commenters should send only one copy of written comments, or if comments are filed electronically, commenters should submit them only one time. We will file in the docket all comments that we receive, as well as a report summarizing each substantive public contact with FAA personnel concerning this rulemaking during the comment period. We will consider all the comments we receive and may conduct additional rulemaking based on those comments.
On October 28, 2015 we issued Emergency AD 2015-22-52 for Airbus Helicopters Model AS350B3 helicopters with a dual hydraulic system that prohibited performing the yaw load compensator check (collective switch) during preflight procedures and instead required performing it during post-flight procedures. Emergency AD 2015-22-52 also required the yaw servo hydraulic switch (collective switch) to be in the “ON” (forward) position before taking off. Emergency AD 2015-22-52 was sent previously to all known U.S. owners and operators of these helicopters. The actions in Emergency AD 2015-22-52 were intended to prevent takeoff without hydraulic pressure in the T/R hydraulic system, loss of T/R flight control, and subsequent loss of control of the helicopter.
Emergency AD 2015-22-52 was prompted by two accidents and one incident of Airbus Helicopters Model AS350B3 helicopters with a dual hydraulic system installed. From preliminary investigations, loss of T/R control during takeoff was evident in each event. Each event experienced a counterclockwise rotational yaw immediately after takeoff. It was also noted that the anti-torque pedals felt jammed or locked in the neutral position by the pilots in the two non-fatal events. The conditions in the events are indicative of takeoffs without hydraulic T/R assistance caused by a lack of pressure in the T/R hydraulic system. When taking off without T/R hydraulic assistance with the switch on the collective grip in the “OFF” (aft) position, the yaw load compensator remains discharged and degrades the T/R hydraulic system, which significantly increases the pilot T/R control load and prevents sufficient T/R thrust for takeoff.
Based on the accidents and incident, EASA, which is the Technical Agent for the Member States of the European Union, issued EASA AD No. 2015-0178, dated August 26, 2015, to correct an unsafe condition for Airbus Helicopters Model AS 350 B3 helicopters, equipped with a dual hydraulic system identified as modification OP 3082 or OP 3346. EASA advises of a perceived loss of T/R control that mimics jamming during take-off if the T/R hydraulic preflight checks are not performed in accordance with the checklist in the RFM. According to EASA, performing the T/R hydraulic preflight checks improperly may result in reduced function of the T/R hydraulic system, thereby significantly increasing the T/R control load for the pilot.
After we issued Emergency AD 2015-22-52, we received comments noting an error in terminology and a defect in reporting compliance that resulted in confusion in how to comply with Emergency AD 2015-22-52. Specifically, we referred to the collective switch for the yaw load compensator check, when we should have referred to the ACCU TST switch. Activating the collective switch after rotor shut-down will have no effect due to the absence of hydraulic pressure in the system. We also omitted a method of recording compliance. Therefore, on October 30, 2015, we issued Emergency AD 2015-22-53 to supersede Emergency AD 2015-22-52 to correct the error in terminology and the defect in recording compliance. Emergency AD 2015-22-53 requires revising the normal operating procedures section of the RFM to prohibit performing the yaw load compensator check (ACCU TST switch) during preflight procedures and instead require performing it during post-flight procedures after rotor shut-down. Emergency AD 2015-22-53 also requires revising the RFM to state that
This helicopter has been approved by the aviation authority of France and is approved for operation in the United States. Pursuant to our bilateral agreement with France, EASA, its technical representative, has notified us of the unsafe condition described in the EASA AD. We are issuing this AD because we evaluated all information provided by EASA and determined the unsafe condition exists and is likely to exist or develop on other helicopters of this same type design.
Airbus Helicopters issued Service Bulletin No. AS350-67.00.66, Revision 1, dated October 22, 2015 (SB AS350-67.00.66), which specifies inserting specific pages of the bulletin into the RFM. These pages revise the preflight and post-flight hydraulic checks by moving the T/R yaw load compensator check from preflight to post-flight. These pages also revise terminology within the flight manuals for the different engine configurations.
Airbus Helicopters also issued Safety Information Notice No. 2944-S-29, Revision 0, dated August 26, 2015 (SIN 2944-S-29), which warns that attempting to take off without T/R hydraulic assistance (which may be caused by the yaw servo hydraulic switch on the collective grip in the “OFF” (aft) position) might be incorrectly perceived as T/R control failure (jam), which could lead to loss of control of the helicopter if not quickly identified and corrected. SIN 2944-S-29 also advises of the RFM update that revises the run-up hydraulic check starting procedures to no longer specify “pressing” the yaw servo hydraulic switch. To mitigate this potential error, the yaw load compensator check has been moved from preflight to post-flight procedures. Further, SIN 2944-S-29 states the yaw servo hydraulic switch, which is located on the collective grip, is also called the hydraulic pressure switch or hydraulic cut off switch in various RFMs.
This AD requires, before further flight, revising the RFM to stop performing the yaw load compensator check (ACCU TST switch) during preflight procedures and instead perform the yaw load compensator check during post-flight procedures after rotor shut-down. This AD also requires revising the RFM to state that the yaw servo hydraulic switch (collective switch) must be in the “ON” (forward) position before taking off.
The EASA AD requires revising the RFM by incorporating procedures contained in Airbus Helicopters Service Bulletin No. AS350-67.00.66, Revision 0, dated August 26, 2015, and informing all flight crew of the RFM changes. This AD requires revising the RFM by inserting a copy of this AD or by making pen and ink changes.
We consider this AD to be an interim action. The design approval holder is currently developing a terminating action that will address the unsafe condition identified in this AD. Once this terminating action is developed, approved, and available, we might consider additional rulemaking.
We estimate that this AD affects 427 helicopters of U.S. Registry. We estimate that operators may incur the following costs in order to comply with this AD at an average labor rate of $85 per work-hour. It takes about 0.5 work-hour to revise an RFM for a cost of $43 per helicopter and $18,361 for the U.S. fleet.
Providing an opportunity for public comments prior to adopting these AD requirements would delay implementing the safety actions needed to correct this known unsafe condition. Therefore, we found and continue to find that the risk to the flying public justifies waiving notice and comment prior to the adoption of this rule because the previously described unsafe condition can adversely affect the controllability of the helicopter and the initial required action must be accomplished before further flight.
Since it was found that immediate corrective action was required, notice and opportunity for prior public comment before issuing this AD were impracticable and contrary to public interest and good cause existed to make the AD effective immediately by Emergency AD 2015-22-53, issued on October 30, 2015, to all known U.S. owners and operators of these helicopters. These conditions still exist and the AD is hereby published in the
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.
We are 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.
We determined that this AD will not have federalism implications under Executive Order 13132. This AD will 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.
For the reasons discussed, I certify that this AD:
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);
3. Will not affect intrastate aviation in Alaska to the extent that it justifies making a regulatory distinction; and
4. Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
We prepared an economic evaluation of the estimated costs to comply with this AD and placed it in the AD docket.
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA amends 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
This AD applies to Airbus Helicopters Model AS350B3 helicopters with a dual hydraulic system installed, certificated in any category.
The dual hydraulic system for Model AS350B3 helicopters is referred to as Airbus modification OP 3082 or OP 3346.
This AD defines the unsafe condition as lack of hydraulic pressure in a tail rotor (T/R) hydraulic system. This condition could result in loss of T/R flight control and subsequent loss of control of the helicopter.
This AD supersedes Emergency AD 2015-22-52, Directorate Identifier 2015-SW-074-AD, dated October 28, 2015.
This AD becomes effective December 16, 2015 to all persons except those persons to whom it was made immediately effective by Emergency AD 2015-22-53, issued on October 30, 2015, which contains the requirements of this AD.
You are responsible for performing each action required by this AD within the specified compliance time unless it has already been accomplished prior to that time.
Before further flight, insert a copy of this AD into the rotorcraft flight manual, Section 4 Normal Operating Procedures, or make pen and ink changes to the preflight and post-flight procedures as follows:
(1) Stop performing the yaw load compensator check (ACCU TST switch) during preflight procedures, and instead perform the yaw load compensator check during post-flight procedures after rotor shut-down.
(2) The yaw servo hydraulic switch (collective switch) must be in the “ON” (forward) position before takeoff.
The yaw servo hydraulic switch is also called the hydraulic pressure switch or hydraulic cut off switch in various Airbus Helicopters rotorcraft flight manuals.
Special flight permits are prohibited.
(1) The Manager, Safety Management Group, FAA, may approve AMOCs for this AD. Send your proposal to: Stephen Barbini, Flight Test Engineer, Regulations and Policy Group, Rotorcraft Directorate, FAA, 10101 Hillwood Pkwy, Fort Worth, TX 76177; telephone (817) 222-5110; email
(2) For operations conducted under a 14 CFR part 119 operating certificate or under 14 CFR part 91, subpart K, we suggest that you notify your principal inspector, or lacking a principal inspector, the manager of the local flight standards district office or certificate holding district office, before operating any aircraft complying with this AD through an AMOC.
(1) Airbus Helicopters Service Bulletin No. AS350-67.00.66, Revision 1, dated October 22, 2015, and Airbus Helicopters Safety Information Notice No. 2944-S-29, Revision 0, dated August 26, 2015, which are not incorporated by reference, contain additional information about the subject of this AD. For service information identified in this AD, contact Airbus Helicopters, 2701 N. Forum Drive, Grand Prairie, TX 75052; telephone (972) 641-0000 or (800) 232-0323; fax (972) 641-3775; or at
(2) The subject of this AD is addressed in European Aviation Safety Agency (EASA) AD No. 2015-0178, dated August 26, 2015. You may view the EASA AD on the Internet at
Joint Aircraft Service Component (JASC) Code: 2910, Main Hydraulic System.
Office of National Marine Sanctuaries (ONMS), National Ocean Service (NOS), National Oceanic and Atmospheric Administration (NOAA), Department of Commerce (DOC).
Final rule; delay of effectiveness for discharge requirements with regard to Coast Guard activities.
The National Oceanic and Atmospheric Administration (NOAA) expanded the boundaries of Gulf of the Farallones National Marine Sanctuary (now renamed Greater Farallones National Marine Sanctuary or GFNMS) and Cordell Bank National Marine Sanctuary (CBNMS) to an area north and west of their previous boundaries with a final rule published on March 12, 2015. The Final Rule entered into effect on June 9, 2015. At that time, NOAA postponed the effectiveness of the discharge requirements in both sanctuaries' regulations with regard to U.S. Coast Guard activities for 6 months. This document extends the postponement of the discharge requirements for these activities for another 6 months to provide adequate time for completion of an environmental assessment, and subsequent rulemaking, as appropriate.
The effectiveness for the discharge requirements in both CBNMS and GFNMS expansion areas with regard to U.S. Coast Guard activities is June 9, 2016.
Copies of the FEIS, final management plans, and the final rule published on March 12, 2015 can be viewed or downloaded at
Maria Brown, Greater Farallones National Marine Sanctuary Superintendent, at
On March 12, 2015, NOAA expanded the boundaries of Gulf of the Farallones National Marine Sanctuary (now renamed Greater Farallones National Marine Sanctuary or GFNMS) and Cordell Bank National Marine Sanctuary (CBNMS) to an area north and west of their previous boundaries with a final rule (80 FR 13078). The Final Rule entered into effect on June 9, 2015 (80 FR 34047). At that time, NOAA postponed the effectiveness of the discharge requirements in both sanctuaries' regulations with regard to U.S. Coast Guard (USCG) activities for 6 months.
This document postpones the effectiveness of the discharge requirements in both sanctuaries with regard to USCG activities for another 6 months, until June 9, 2016. In the course of the rule making to expand GFNMS and CBNMS, NOAA learned from USCG that the discharge regulations had the potential to impair the operations of USCG vessels and air craft conducting law enforcement and on-water training exercises in GFNMS and CBNMS. The USCG supports national marine sanctuary management by providing routine surveillance and dedicated law enforcement of the National Marine Sanctuaries Act and sanctuary regulations.
To ensure that the March 12, 2015 rule does not undermine USCG's ability to perform its duties, NOAA postponed for 6 months the effectiveness of the discharge requirements for USCG operations. Specifically, the effectiveness of the discharge requirements was postponed until December 9, 2015. However, NOAA needs more time to assess USCG activities and develop alternatives for an environmental assessment developed pursuant to the requirements of the National Environmental Policy Act. Therefore, NOAA is postponing the effectiveness of the discharge requirements with respect to USCG operations for another 6 months, until June 9, 2016. During this time, NOAA will consider how to address USCG's concerns and will consider, among other things, whether to exempt certain USCG activities in sanctuary regulations. The public, other federal agencies, and interested stakeholders will be given an opportunity to comment on various alternatives that are being considered. This will include the opportunity to review any proposed rule and related environmental analysis.
16 U.S.C. 1431
Pension Benefit Guaranty Corporation.
Final rule.
This rule amends the Pension Benefit Guaranty Corporation's regulation on Allocation of Assets in Single-Employer Plans by substituting a new table for determining expected retirement ages for participants in pension plans undergoing distress or involuntary termination with valuation dates falling in 2016. This table is needed in order to compute the value of early retirement benefits and, thus, the total value of benefits under a plan.
Effective January 1, 2016.
Catherine B. Klion (
The Pension Benefit Guaranty Corporation (PBGC) administers the pension plan termination insurance program under Title IV of the Employee Retirement Income Security Act of 1974 (ERISA). PBGC's regulation on Allocation of Assets in Single-Employer Plans (29 CFR part 4044) sets forth (in subpart B) the methods for valuing plan benefits of terminating single-employer plans covered under Title IV. Guaranteed benefits and benefit liabilities under a plan that is undergoing a distress termination must be valued in accordance with subpart B of part 4044. In addition, when PBGC terminates an underfunded plan involuntarily pursuant to ERISA section 4042(a), it uses the subpart B valuation rules to determine the amount of the plan's underfunding.
Under § 4044.51(b) of the asset allocation regulation, early retirement benefits are valued based on the annuity starting date, if a retirement date has been selected, or the expected retirement age, if the annuity starting date is not known on the valuation date. Sections 4044.55 through 4044.57 set forth rules for determining the expected retirement ages for plan participants entitled to early retirement benefits. Appendix D of part 4044 contains tables to be used in determining the expected early retirement ages.
Table I in appendix D (Selection of Retirement Rate Category) is used to determine whether a participant has a low, medium, or high probability of retiring early. The determination is based on the year a participant would reach “unreduced retirement age” (
Tables II-A, II-B, and II-C (Expected Retirement Ages for Individuals in the Low, Medium, and High Categories respectively) are used to determine the expected retirement age after the probability of early retirement has been determined using Table I. These tables establish, by probability category, the expected retirement age based on both the earliest age a participant could retire under the plan and the unreduced retirement age. This expected retirement age is used to compute the value of the early retirement benefit and, thus, the total value of benefits under the plan.
This document amends appendix D to replace Table I-15 with Table I-16 in order to provide an updated correlation, appropriate for calendar year 2016, between the amount of a participant's benefit and the probability that the participant will elect early retirement. Table I-16 will be used to value benefits in plans with valuation dates during calendar year 2016.
PBGC has determined that notice of, and public comment on, this rule are impracticable and contrary to the public interest. Plan administrators need to be able to estimate accurately the value of plan benefits as early as possible before initiating the termination process. For that purpose, if a plan has a valuation date in 2016, the plan administrator needs the updated table being promulgated in this rule. Accordingly, the public interest is best served by issuing this table expeditiously, without an opportunity for notice and comment, to allow as much time as possible to estimate the value of plan benefits with the proper table for plans with valuation dates in early 2016.
PBGC has determined that this action is not a “significant regulatory action” under the criteria set forth in Executive Order 12866.
Because no general notice of proposed rulemaking is required for this regulation, the Regulatory Flexibility
Pension insurance, Pensions.
In consideration of the foregoing, 29 CFR part 4044 is amended as follows:
29 U.S.C. 1301(a), 1302(b)(3), 1341, 1344, 1362.
Department of the Army, DoD.
Direct final rule.
The Department of the Army is amending the Army Privacy Program Regulation. Specifically, this direct final rule is removing the exemption for A0601-222 USMEPCOM, titled Armed Services Military Accession Testing. Based on a recent review of A0601-222 Armed Services Military Accession Testing it has been determined that records in this system will now be covered by DMDC 15 DoD, Armed Services Military Accession Testing, which published in the
The rule will be effective on February 4, 2016 unless comments are received that would result in a contrary determination. Comments will be accepted on or before February 1, 2016.
You may submit comments, identified by docket number and/or Regulatory Information Number (RIN) and title, by any of the following methods:
•
•
Ms. Tracy Rogers, Chief, FOIA/PA, telephone: 703-428-6513.
The revisions to this rule will be reported in future status updates as part of DoD's retrospective plan under Executive Order 13563 completed in August 2011. DoD's full plan can be accessed at:
DoD has determined this rulemaking meets the criteria for a direct final rule because it involves changes dealing with DoD's management of its Privacy Programs. DoD expects no opposition to the changes and no significant adverse comments. However, if DoD receives a significant adverse comment, the Department will withdraw this direct final rule by publishing a notice in the
This rule provides policy and procedures for Army's implementation of the Privacy Act of 1974, as amended. The Army is removing an exemption rule from the exemptions section. This regulatory action imposes no monetary costs to the Agency or public.
Executive Orders 12866 and 13563 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distribute impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. It has been determined that this rule is not a significant rule.
It has been determined that this rule does not have significant economic impact on a substantial number of small entities because it is concerned only with the administration of Privacy Act within the Department of Defense.
It has been determined that this rule imposes no information collection requirements on the public under the Paperwork Reduction Act of 1995.
It has been determined that this rule does not involve a Federal mandate that may result in the expenditure by State, local and tribal governments, in the aggregate, or by the private sector, of $100 million or more and that such rulemaking will not significantly or uniquely affect small governments.
It has been determined that this rule does not have federalism implications. This rule does 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.
Privacy.
Accordingly 32 CFR part 505 is amended as follows:
Pub. L. 93-579, Stat. 1896 (5 U.S.C. 552a).
National Park Service, Interior.
Final rule.
The National Park Service is authorizing a solid waste transfer station near Stehekin, Washington, within the boundary of Lake Chelan National Recreation Area, that does not meet all the siting criteria of the general National Park Service regulations and accepts solid waste generated within the boundary of the recreation area from non-National Park Service activities.
This rule is effective December 31, 2015.
Kerri L. Cook, Facility Operations Specialist, National Park Service, North Cascades National Park Complex, 810 State Route 20, Sedro-Woolley, WA 98284; (360) 854-7280. Email:
On December 22, 1994, the National Park Service (NPS) adopted regulations codified at 36 CFR part 6 to implement a statutory requirement of Public Law 98-506 (54 U.S.C. 100903) (Act), which was enacted in 1984. The Act prohibits the operation of a solid waste disposal site within the boundary of any unit of the National Park System except for those operating as of September 1, 1984, or those “used only for disposal of wastes generated within that unit of the park system so long as such site will not degrade any of the natural or cultural resources of such park unit.” The Act directed the Secretary of the Interior to promulgate regulations “to carry out the provisions of this subsection, including reasonable regulations to mitigate the adverse effects of solid waste disposal sites in operation as of September 1, 1984, upon property of the United States.”
The general regulations at 36 CFR part 6 ordinarily control both existing and new solid waste disposal sites within the boundaries of any unit of the National Park System to ensure that operation of such sites will not degrade the natural or cultural resources of the park unit. Transfer stations are included in the definition of “solid waste disposal site” in § 6.3 and are therefore subject to 36 CFR part 6.
Section 6.4(a) prohibits any person (including NPS) from operating a new solid waste disposal site within the boundaries of a park unit unless the criteria in § 6.4(a) are met. Section 6.4(a)(1) requires that the solid waste handled by the site is generated solely from “National Park Service activities,” defined in § 6.3 as “operations conducted by the National Park Service or a National Park Service contractor, concessionaire or commercial use licensee.” Section 6.4(a)(9) requires that “the site is not located within one mile of a National Park Service visitor center, campground, ranger station, entrance station, or similar public use facility, or a residential area.” Section 6.4(a)(10) requires that the site is not detectable by public sight, sound, or odor from a scenic vista, a public use facility, a designated or proposed wilderness area, a site listed on (or eligible for listing on) the National Register of Historic Places, or a public road. Section 6.8(a) prohibits the NPS from accepting waste at an NPS operated solid waste disposal site, except for waste generated by NPS activities.
The NPS is promulgating a park-specific regulation in 36 CFR 7.62 to authorize a limited exception to the general regulations described above. The rule authorizes an NPS transfer station on federal lands near Stehekin,
Stehekin is a remote community of approximately 75 year-round, plus 80 seasonal, residents located on privately owned land within the statutory boundary of LACH. Stehekin is located at the head of 55-mile-long Lake Chelan and is accessible only by boat, float plane, or foot trail. Non-NPS services and facilities in Stehekin include seasonal lodging, food operations, and other small businesses that help support 35,000-45,000 park visitors annually. The NPS operates the only facility in the Stehekin Valley for the management of solid waste. Waste consolidated at the NPS transfer station is shipped by barge 55 miles down the lake for ultimate disposal. The geographically isolated private residents and businesses in Stehekin have no feasible method of properly disposing solid waste other than at the NPS transfer station. Consequently, the NPS has for many years accepted Stehekin community waste in its transfer station to deter small dumps on private lands and illegal dumping on public lands. Although the Act does not prohibit the NPS from receiving Stehekin waste, this waste does not qualify as waste generated from “National Park Service activities” under the existing regulations, so the current practice of accepting waste from Stehekin at the existing NPS transfer station conflicts with 36 CFR 6.8(a).
The existing NPS transfer station is located within the 100-year floodplain and is part of a larger maintenance facility that is being relocated outside of the Stehekin River floodplain due to frequent flooding.
The NPS has determined that in these unique circumstances, it will best protect park resources to allow the NPS transfer station, whether at the existing or proposed location, to accept waste generated by the community of Stehekin, notwithstanding the prohibition on accepting non-NPS waste in §§ 6.4(a)(1) and 6.8(a) and the siting criteria in § 6.4(a)(9) and (10). Due to its geographic isolation, the community of Stehekin has no environmentally responsible or practicable alternative for the disposal of its waste, much of which is generated by the provision of essential services to thousands of park visitors each year. Prohibiting this community from using the existing or proposed NPS transfer station could result in the illegal disposal of waste on park lands, or other disposal practices which would degrade the natural resources of LACH. In this exceptional situation, accepting non-NPS-generated waste for transfer and ultimate disposal outside the park boundary will pose significantly fewer environmental land use concerns than other alternatives. This determination is supported by the analysis contained in the November 2014 Replacement of Administrative Facilities at Stehekin Environmental Assessment (EA) and the August 2015 Finding of No Significant Impact (FONSI), which examine the environmental impacts of the continued operation of the existing NPS transfer station and the construction and operation of the new transfer station, which will employ contemporary environmental methods for handling waste.
The NPS promulgates a special regulation to authorize an exception to a prohibition found in a general regulation only in limited circumstances. The only other exceptions to the part 6 requirements have been granted by special regulation for Alaskan parks under similar circumstances, where geographically isolated communities have no feasible alternative for solid waste disposal that complies with the part 6 requirements. The rule accommodates the circumstances of the Stehekin community which is located in a remote area within the boundary of LACH and has no other practicable options for environmentally responsible solid-waste disposal. It is designed only to authorize the operation of the existing transfer station and the proposed transfer station at the locations identified in the EA, which the NPS believes will best protect park resources based upon the analysis contained in the EA. All other requirements in part 6 will remain in effect and apply to the existing and new NPS transfer station, including the requirement in § 6.4(a)(3) that the site of the existing and new facility “will not degrade any of the natural or cultural resources” of LACH. The rule is consistent with the Act, which does not prohibit new solid waste disposal sites from handling waste generated by non-NPS activities within a park unit provided that the site will not degrade any of the park unit's natural or cultural resources. The rule does not supersede or replace other requirements applicable to solid waste disposal sites, including the policy (unless there is an approved waiver) in Director's Order #35B (Sale of National Park Service Produced Utilities) that NPS recover the cost of utilities (including the collection and disposal of solid waste) provided to non-NPS users.
Under these circumstances, the NPS has determined that the exceptions to part 6 in the rule are appropriate and the sites will not degrade the park's natural or cultural resources.
The NPS published the proposed rule at 80 FR 39985 (July 13, 2015). The NPS accepted comments through the mail, hand delivery, and the Federal eRulemaking Portal at
Executive Order 12866 provides that the Office of Information and Regulatory Affairs (OIRA) in the Office of Management and Budget will review all significant rules. OIRA has determined that this rule is not significant.
Executive Order 13563 reaffirms the principles of Executive Order 12866 while calling for improvements in the nation's regulatory system to promote predictability, to reduce uncertainty, and to use the best, most innovative, and least burdensome tools for achieving regulatory ends. The executive order directs agencies to consider regulatory approaches that reduce burdens and maintain flexibility and freedom of choice for the public where these approaches are relevant, feasible, and consistent with regulatory objectives. It emphasizes further that regulations must be based on the best available science and that the rulemaking process must allow for public participation and an open exchange of ideas. We have developed this rule in a manner consistent with these requirements.
This rulemaking will not have a significant economic effect on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
This rule is not a major rule under 5 U.S.C. 804(2), the SBREFA. This rule:
a. Does not have an annual effect on the economy of $100 million or more.
b. Will not cause a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions.
c. Does not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises.
This rule does not impose an unfunded mandate on State, local, or tribal governments, or the private sector of more than $100 million per year. The rule does not have a significant or unique effect on State, local, or tribal governments or the private sector. A statement containing the information required by the Unfunded Mandates Reform Act (2 U.S.C. 1531
This rule does not effect a taking of private property or otherwise have taking implications under Executive Order 12630. A takings implication assessment is not required.
Under the criteria in section 1 of Executive Order 13132, this rule does not have sufficient federalism implications to warrant the preparation of a Federalism summary impact statement. A Federalism summary impact statement is not required.
This rule complies with the requirements of Executive Order 12988. Specifically, this rule:
a. Meets the criteria of section 3(a) requiring that all regulations be reviewed to eliminate errors and ambiguity and be written to minimize litigation; and
b. Meets the criteria of section 3(b)(2) requiring that all regulations be written in clear language and contain clear legal standards.
The Department of the Interior strives to strengthen its government-to-government relationship with Indian Tribes through a commitment to consultation with Indian Tribes and recognition of their right to self-governance and tribal sovereignty. We have evaluated this rule under the criteria in Executive Order 13175 and under the Department's tribal consultation policy and have determined that tribal consultation is not required because the rule will have no substantial direct effect on federally recognized Indian tribes.
In May and July 2014, the NPS sent letters to the Tribal Historic Preservation Officers for the Colville Confederated Tribes and the Confederated Tribes and Bands of the Yakama Nation inviting comment regarding the inventory, evaluation, and finding of no effect on cultural resources within the project area. This encompasses the relocation of all maintenance facilities, including the transfer station, as proposed in the preferred alternative (Alternative 2) in the EA. These tribes did not identify any concerns related to the project.
This rule does not contain information collection requirements, and a submission to the Office of Management and Budget under the Paperwork Reduction Act is not required. We may not conduct or sponsor and you are not required to respond to a collection of information unless it displays a currently valid OMB control number.
This rule does not constitute a major Federal action significantly affecting the quality of the human environment. A detailed statement under the NEPA is not required because we reached a Finding of No Significant Impact. This rule implements part of the preferred alternative (Alternative 2) in the EA, which is the selected alternative in the FONSI. The EA and FONSI are referenced above and available online at
This rule is not a significant energy action under the definition in Executive Order 13211. A Statement of Energy Effects is not required.
The primary author of this regulation is Jay Calhoun, Regulations Program Specialist, Division of Regulations, Jurisdiction, and Special Park Uses, National Park Service, 1849 C Street NW., Washington, DC 20240.
National parks, Reporting and recordkeeping requirements.
In consideration of the foregoing, the NPS amends 36 CFR part 7 as follows:
54 U.S.C. 100101, 100751, 320102; Sec. 7.96 also issued under D.C. Code 10-137 and D.C. Code 50-2201.07.
(d)
(1) Accept solid waste generated within the boundary of the park unit that was not generated by National Park Service activities;
(2) Be located within one mile of a campground or a residential area;
(3) Be visible by the public from scenic vistas or off-trail areas in designated wilderness areas;
(4) Be detectable by the public by sound from a campground; and
(5) Be detectable by the public by sight, sound, or odor from a road open to public travel.
Department of Veterans Affairs.
Interim final rule.
The Department of Veterans Affairs (VA) revises its medical regulations that implement section 101 of the Veterans Access, Choice, and Accountability Act of 2014 (hereafter referred to as “the Choice Act”), which requires VA to establish a program to furnish hospital care and medical services through eligible non-VA health care providers to eligible veterans who either cannot be seen within the wait-time goals of the Veterans Health Administration (VHA) or who qualify based on their place of residence (hereafter referred to as the “Veterans Choice Program” or the “Program”). These regulatory revisions are required by the most recent amendments to the Choice Act made by the Construction Authorization and Choice Improvement Act of 2014, and by the Surface Transportation and Veterans Health Care Choice Improvement Act of 2015. The Construction Authorization and Choice Improvement Act of 2014 amended the Choice Act to define additional criteria that VA may use to determine that a veteran's travel to a VA medical facility is an “unusual or excessive burden,” and the Surface Transportation and Veterans Health Care Choice Improvement Act of 2015 amended the Choice Act to cover all veterans enrolled in the VA health care system, remove the 60-day limit on an episode of care, modify the wait-time and 40-mile distance eligibility criteria, and expand provider eligibility based on criteria as determined by VA. This interim final rule revises VA regulations consistent with the changes made to the Choice Act as described above.
Kristin Cunningham, Director, Business Policy, Chief Business Office (10NB), Veterans Health Administration, Department of Veterans Affairs, 810 Vermont Avenue NW., Washington, DC 20420, (202) 382-2508. (This is not a toll-free number.)
The Veterans Access, Choice, and Accountability Act of 2014 (the Choice Act, Pub. L. 113-146, 128 Stat. 1754) was enacted on August 7, 2014. Further amendments to the Choice Act were made on September 26, 2014, by the Department of Veterans Affairs Expiring Authorities Act of 2014 (Pub. L. 113-175, 128 Stat. 1901, 1906); on December 16, 2014, by the Consolidated and Further Continuing Appropriations Act of 2015 (Pub. L. 113-235, 128 Stat. 2130, 2568); on May 22, 2015, by the Construction Authorization and Choice Improvement Act (Pub. L. 114-19, 129 Stat. 215); and on July 31, 2015, by the Surface Transportation and Veterans Health Care Choice Improvement Act (Pub. L. 114-41, 129 Stat. 443). This interim final rule revises VA regulations that implement the Choice Act in accordance with the most recent amendments made by Public Laws 114-19 and 114-41. Prior to discussing the regulatory changes made in this interim final rule, a brief history of previous rulemakings that created and revised regulations that implement the Choice Act is provided below.
Section 101 of the Choice Act creates the Veterans Choice Program (the Program) and requires VA to enter into agreements with identified eligible non-Department of Veterans Affairs (VA) entities or providers to furnish hospital care and medical services to eligible veterans who elect to receive care under the Program. Sec. 101(a)(1)(A), Public Law 113-146, 128 Stat. 1754. On November 5, 2014, VA published an interim final rule, as required by section 101(n) of the Choice Act, to implement the Veterans Choice Program through new regulations at 38 CFR 17.1500-17.1540. 79 FR 65571 (hereafter referred to as the “November interim final rule”). VA published another interim final rule on April 24, 2015, modifying § 17.1510(e) to revise the methodology for calculating distances under that section from geodesic (or “straight-line”) distance to driving distance. 80 FR 22906 (hereafter referred to as the “April interim final rule”). VA published a final rule (hereafter referred to as the “final rule”) amending the payment rates in the Program to account for two exceptions: One for Alaska, and one for states with an All-Payer Model Agreement (Maryland). These two payment rate exceptions were authorized by section 242 of Division I of Public Law 113-235. 128 Stat. 2568.
Under the November interim final rule at § 17.1510(b)(4)(ii), veterans may be eligible to participate in the Veterans Choice Program if they live 40 miles or less from a VA medical facility but face an “unusual or excessive burden” in traveling to such medical facility based on the presence of a body of water or a geologic formation that cannot be crossed by road. As explained in the November interim final rule, this standard for “unusual or excessive burden” was VA's interpretation of the language in the Choice Act, which at that time required the burden to be “due to geographical challenges, as determined by the Secretary.” Sec. 101(b)(2)(D)(ii)(II), Pub. L. 113-146, 128 Stat. 1754. As explained in the final rule, section 3(a)(2) of Public Law 114-19 amended section 101(b)(2)(D)(ii)(II) of the Choice Act by defining additional criteria that could be the basis for finding that a veteran faced an “unusual or excessive burden” in traveling to receive care in a VA medical facility, including environmental factors such as roads that are not accessible to the general public, traffic, or hazardous weather; a medical condition that affects the ability to travel; or other factors, as determined by the Secretary. VA implemented two of these factors, namely the environmental factors such as roads that are not accessible to the general public, traffic, or hazardous weather, or a medical condition that affects the ability to travel, ahead of these regulatory revisions. We did so because we believe these factors are
In addition to the express factors in section 3(a)(2) of Public Law 114-19 that are related to the environment or that are related to the medical condition of a veteran, we add three “other factors” to § 17.1510(b)(4)(ii)(A) through (C) that the Secretary may consider when determining whether a veteran faces an unusual or excessive burden in travelling to a VA medical facility that is 40 miles or less from their residence. These criteria are newly implemented in this interim final rule and are not intended to be an exhaustive list, although VA anticipates they will address the majority of cases that could reasonably be the basis for finding an unusual or excessive burden in travel. These other factors are the nature or simplicity of the hospital care or medical services the veteran requires, how frequently the veteran needs hospital care or medical services, and the need for an attendant, which is defined as a person who provides required aid and/or physical assistance to the veteran, for a veteran to travel to a VA medical facility for hospital care or medical services. Considering the nature or simplicity of the care or services will allow VA to determine, for example, that routine and simple procedures that do not necessarily require the expertise or best practices of VA providers (such as simple tests or treatments like an allergy test or an immunization) do not justify traveling a longer distance just to receive that care from VA. Similarly, if a veteran needs repeated appointments for a course of treatment, such as chemotherapy, the frequency of travel could become an excessive burden on the veteran that could be alleviated or lessened by receiving care closer to home. If a veteran requires an attendant to travel to a VA medical facility, this could also create an excessive or unusual burden on the veteran, as he or she may need to arrange transportation with another person. VA will define the term “attendant” to include any person who provides required aid and/or physical assistance to the veteran to travel to a VA medical facility for hospital care or medical services. This definition is consistent with the definition of this term in VA's beneficiary travel regulation (see 38 CFR 70.2.), but the definition at § 70.2 is dependent on separate eligibility under the beneficiary travel program, and therefore is not cross referenced in § 17.1510(b)(4)(ii)(C). The list of factors in § 17.1510(b)(4)(ii)(A) through (C) is demonstrative and not exhaustive. There may be other unique factors that create an unusual or excessive burden for a veteran, and in such cases, VA will make a determination on a case-by-case basis.
Section 4005 of the Surface Transportation and Veterans Health Care Choice Improvement Act of 2015 amended section 101 of the Choice Act to: Remove the August 1, 2014 enrollment date restriction, thereby making all veterans enrolled in the VA health care system under § 17.36 eligible for the Program if they meet its other eligibility criteria; remove the 60-day limit on an episode of care; modify wait-time eligibility requirements; modify the 40-mile distance eligibility criterion; and expand provider eligibility based on criteria as determined by VA. Sec. 4005, Public Law 114-41, 129 Stat. 443. Paragraph (a) of § 17.1510 is therefore revised, and paragraphs (a)(1) and (2) are removed, so it is clear under revised § 17.1510(a) that all veterans enrolled under § 17.36 are potentially eligible, as required by subsection (b) of section 4005 of Public Law 114-41. VA has already implemented these changes related to removal of the August 1, 2014 enrollment date ahead of the regulatory revisions in this interim final rule. These changes were not subject to notice and comment prior to implementation because they had an immediate effective date and VA did not need to interpret the language to give it effect. These changes are merely a restatement of existing statutory law to make our regulations consistent with Congressional intent as well as consistent with our current practice. VA enrolls new veterans every day, so these changes have allowed more veterans who also meet the other eligibility requirements under § 17.1510 to be eligible for the Program.
We discuss below the remaining changes made by Public Law 114-41 to section 101 of the Choice Act that are newly implemented in this interim final rule. Section 4005(a) of Public Law 114-41 amended section 101(h) of the Choice Act by removing the 60-day
Section 4005(d) of Public Law 114-41 amended section 101(b)(2)(A) of the Choice Act to create eligibility for veterans that are unable to be scheduled for an appointment within “the period determined necessary for [clinically necessary] care or services if such period is shorter than” VHA's wait time goals. Sec. 4005(d), Public Law 114-41, 129 Stat. 443. This new wait-times based criterion is added as paragraph (b)(1)(ii) of § 17.1510, and creates eligibility when VA clinically determines that a veteran requires care within a period of time that is shorter than 30 days from the date an appointment is deemed clinically appropriate by a VA health care provider, or shorter than 30 days from the date that a veteran prefers to be seen.
Section 4005(e) of Public Law 114-41 amended section 101(b)(2)(B) of the Choice Act to modify the 40-mile distance eligibility criterion. Section 101(b)(2)(B)(i)-(ii) of the Choice Act now provides that veterans may be eligible if they reside more than 40 miles from “(i) with respect to a veteran who is seeking primary care, a medical facility of the Department, including a community-based outpatient clinic, that is able to provide such primary care by a full-time primary care physician; or (ii) with respect to a veteran not covered under clause (i), the medical facility of the Department, including a community-based outpatient clinic, that is closest to the residence of the veteran.” We find it would be impracticable to apply a “seeking primary care” eligibility criterion as literally written in the Act. Many individuals that seek VA care generally do not specifically “seek” primary care, but rather “seek” treatment for a specific complaint, and are directed first to primary care for the very purpose of determining what health care needs must be addressed. For instance, a veteran who is eligible for the Program and who seeks VA care for a complaint of generalized back pain would in most cases be directed first to primary care and not immediately to an orthopedist or chiropractor. Under a strict reading of the phrase “seeking primary care” in section 4005(e) of Public Law 114-41, such a veteran might not be considered eligible under the new section 101(b)(2)(B)(i) criterion because they did not specifically “seek” primary care.
Rather than make this distinction, between those veterans “seeking primary care” and those not “seeking primary care,” we interpret section 4005(e) of Public Law 114-41 as a clarification of the eligibility criterion for the 40-mile distance determination. Effectively, this would raise the threshold for what constitutes a qualifying VA medical facility to include only those facilities with at least a full-time primary care physician. For instance, previously, if a veteran lived 10 miles from a VA-community based outpatient clinic (CBOC) that did not have a full-time primary care physician, but lived 50 miles from another VA medical facility that did, the veteran would not be eligible for the Program because of their proximity to the CBOC. Under this interim final rule, however, that veteran would be eligible for the Program because the nearest VA medical facility with a full-time primary care physician is more than 40 miles away. We therefore do not revise the general 40-mile requirement in § 17.1510(b)(1), but do revise § 17.1505 to add a definition of “full-time primary care physician,” as well as amend the definition of “VA medical facility” to require that such a facility have a full-time primary care physician. We note that “full-time primary care physician” will mean at least one individual physician whose workload, or multiple physicians whose combined workload, equates to a 0.9 full time equivalent employee that works at least 36 clinical work hours per week. This definition's requirement that 36 of the 40 hours must be clinical is reasonable to ensure that for purposes of determining eligibility for the Veterans Choice Program, we are taking into account how much clinical work, as opposed to administrative work, a physician actually performs. VA updates full-time equivalent employee data for primary care physicians on a regular basis, and will use such data when making these determinations.
Not distinguishing between those veterans that are “seeking primary care” and other veterans is additionally more veteran-centric because we find that a veteran's access to specialty care can be as important as their access to primary care, and in a majority of cases if a veteran lives more than 40 miles from a VA medical facility with a full-time primary care physician, it is very likely that such veteran also lives more than 40 miles away from a VA medical facility that would be able to provide the vast majority of specialty care that we know our veteran population requires. Lastly, if VA did distinguish between those veterans that are “seeking primary care” versus all other veterans who otherwise live more than 40 miles from a VA facility with a full-time primary care physician, this may have the effect of creating an unintentional back door for veteran eligibility in the Program, whereby veterans might be directed to seek primary care to be determined eligible, when such veterans may not actually need primary care. This interpretation gives effect to section 4005(e) of Public Law 114-41 by accounting for those veterans that would be specifically “seeking primary care” and that live more than 40 miles from a VA facility with a full-time primary care physician, as well as for
Section 4005(c) of Public Law 114-41 amended sections 101(a)(1)(B) and 101(d) of the Choice Act to permit VA to expand provider eligibility beyond those providers expressly listed in section 101(a)(1)(B) of the Choice Act, in accordance with criteria as established by VA. Sec. 4005(c), Public Law 114-41, 129 Stat. 443. Under the authority of sections 101(a)(1)(B)(v) and 101(d)(5) of the Choice Act, we revise § 17.1530(a) to refer to a new paragraph (e) that will establish eligibility for these other providers, and add a new paragraph (e) to § 17.1530 to list these providers specifically. We also revise paragraph (d) to reorganize current requirements and add new requirements for these providers, in accordance with section 101(d)(5) of the Choice Act. We revise paragraph (d) to retain all requirements related to provider credentialing and licensure, as well as the annual provision to VA of documentation of such requirements, in new paragraph (d)(1)(A). We add paragraph (d)(1)(B) to require that all providers not be excluded from participation in a Federal health care program, as defined in particular sections of the Social Security Act, as well as not be listed as excluded sources or excluded providers or entities in databases and lists maintained under certain Federal programs (such as the System for Award Management or the List of Excluded Individuals and Entities that is maintained by the U.S. Department of Health and Human Services). These requirements in § 17.1530(d)(1)(B) ensure that providers that would participate in the Program are not those that are otherwise excluded from participating in Federal health care programs for a number of reasons, such as being convicted of criminal Medicare or Medicaid fraud, patient abuse or neglect, or felony convictions for other health care-related fraud, theft, or other financial misconduct. Lastly, new paragraph (d)(2) maintains the current requirement that eligible entities must ensure that their providers meet the standards established in § 17.1530(d).
Paragraph 17.1530(e) will specifically add new eligible providers for the Veterans Choice Program. Paragraph (e)(1) of § 17.1530 adds to the list of eligible providers any health care provider that is participating in a State Medicaid plan under title XIX of the Social Security Act (42 U.S.C. 1396
Paragraph (e)(2) will make certain providers of extended care services eligible, namely an Aging and Disability Resource Center, an area agency on aging, or a State agency (as defined in section 102 of the Older Americans Act of 1965 (42 U.S.C. 3002)), or a center for independent living (as defined in section 702 of the Rehabilitation Act of 1973 (29 U.S.C. 796a)). Paragraph (e)(3) of § 17.1530 will establish eligibility for any provider meeting all requirements of § 17.1530(d) that is not listed in section 101(a)(1)(B)(i)-(iv) of the Choice Act or § 17.1530(e)(1)-(e)(2). This is essentially a flexible provision for these regulations so that VA can furnish care under the Program through providers who do not fall into the specific categories listed in section 101(a)(1)(B)(i)-(iv) of the Choice Act or § 17.1530(e)(1)-(e)(2), but satisfy the requirements in § 17.1530(d) to ensure that the provider is skilled and safe to provide services to veterans. This avoids the possible scenario that future required revisions to § 17.1530(e) would create delays in care being provided to veterans under the Program.
To ensure that VA had the resources in place to support care for eligible veterans, the November 2014 interim final rule established different start dates for eligible veterans in § 17.1525 so that implementation of the Program could be phased in. Because the start dates in § 17.1525 have already passed, we remove the language in § 17.1525 to include the section header, but retain § 17.1525 and mark it is as reserved for future use.
The Secretary of Veterans Affairs finds under 5 U.S.C. 553(b)(B) that there is good cause that advance notice and opportunity for public comment are impracticable, unnecessary, or contrary to the public interest and under 5 U.S.C. 553(d)(3) that there is good cause to publish this rule with an immediate effective date. Section 101(n) of the Choice Act authorized VA to implement the Veterans Choice Program through an interim final rule, and provided a deadline of no later than November 5, 2014, the date that is 90 days after the date of the enactment of the law. Additionally, the Program is only authorized to run until August 7, 2017, or until funds expire, which creates a need for expedited action. The changes made by the Construction Authorization and Choice Improvement Act included an immediate effective date under section 3(b) of that Act. These provisions clearly demonstrate that Congress intended that VA act quickly in expanding access to non-VA care options.
This interim final rule changes the criteria VA may consider when determining if a veteran faces an unusual or excessive burden in traveling to the nearest VA medical facility. This interim final rule also expands eligibility for veterans in other ways (through the new criteria related to wait times and to the distance requirements), as well as expands eligibility for providers as required and permitted by the most recent amendments to the Choice Act. These changes will increase the number of veterans who are eligible for the Veterans Choice Program. In order for these veterans to have access to needed health care under the Program, it is essential that the revised criteria be made effective as soon as possible. For the above reasons, we are issuing this rule as an interim final rule. However, VA will consider and address comments that are received within 120 days of the date this interim final rule is published in the
Title 38 of the Code of Federal Regulations, as revised by this interim final rule, represents VA's implementation of its legal authority on this subject. Other than future amendments to this regulation or governing statutes, no contrary guidance or procedures are authorized. All existing or subsequent VA guidance must be read to conform with this
Although this action contains provisions constituting collections of information, at 38 CFR 17.1530(d), under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3521), no new or proposed revised collections of information are associated with this interim final rule. The information collection requirements for § 17.1530(d) are currently approved by the Office of Management and Budget (OMB) and have been assigned OMB control number 2900-0823.
Executive Orders 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, when regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, and other advantages; distributive impacts; and equity). Executive Order 13563 (Improving Regulation and Regulatory Review) emphasizes the importance of quantifying both costs and benefits, reducing costs, harmonizing rules, and promoting flexibility. Executive Order 12866 (Regulatory Planning and Review) defines a “significant regulatory action,” requiring review by OMB, unless OMB waives such review, as “any regulatory action that is likely to result in a rule that may: (1) Have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities; (2) Create a serious inconsistency or otherwise interfere with an action taken or planned by another agency; (3) Materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or (4) Raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in this Executive Order.”
The economic, interagency, budgetary, legal, and policy implications of this regulatory action have been examined, and it has been determined that this is an economically significant regulatory action under Executive Order 12866. VA's regulatory impact analysis can be found as a supporting document at
This regulatory action is a major rule under the Congressional Review Act, 5 U.S.C. 801-08, because it may result in an annual effect on the economy of $100 million or more. Although this regulatory action constitutes a major rule within the meaning of the Congressional Review Act, 5 U.S.C. 804(2), it is not subject to the 60-day delay in effective date applicable to major rules under 5 U.S.C. 801(a)(3) because the Secretary finds that good cause exists under 5 U.S.C. 808(2) to make this regulatory action effective on the date of publication, consistent with the reasons given for the publication of this interim final rule. In accordance with 5 U.S.C. 801(a)(1), VA will submit to the Comptroller General and to Congress a copy of this regulatory action and VA's Regulatory Impact Analysis.
The Unfunded Mandates Reform Act of 1995 requires, at 2 U.S.C. 1532, that agencies prepare an assessment of anticipated costs and benefits before issuing any rule that may result in the expenditure by State, local, and tribal governments, in the aggregate, or by the private sector, of $100 million or more (adjusted annually for inflation) in any 1 year. This interim final rule will have no such effect on State, local, and tribal governments, or on the private sector.
The Secretary hereby certifies that this interim final rule will not have a significant economic impact on a substantial number of small entities as they are defined in the Regulatory Flexibility Act, 5 U.S.C. 601-612. This interim final rule will not have a significant economic impact on participating eligible entities and providers who enter into agreements with VA. To the extent there is any such impact, it will result in increased business and revenue for them. We also do not believe there will be a significant economic impact on insurance companies, as claims will only be submitted for care that will otherwise have been received whether such care was authorized under this Program or not. Therefore, pursuant to 5 U.S.C. 605(b), this rulemaking is exempt from the initial and final regulatory flexibility analysis requirements of 5 U.S.C. 603 and 604.
The Catalog of Federal Domestic Assistance numbers and titles for the programs affected by this document are as follows: 64.007, Blind Rehabilitation Centers; 64.008, Veterans Domiciliary Care; 64.009, Veterans Medical Care Benefits; 64.010, Veterans Nursing Home Care; 64.011, Veterans Dental Care; 64.012, Veterans Prescription Service; 64.013, Veterans Prosthetic Appliances; 64.014, Veterans State Domiciliary Care; 64.015, Veterans State Nursing Home Care; 64.016, Veterans State Hospital Care; 64.018, Sharing Specialized Medical Resources; 64.019, Veterans Rehabilitation Alcohol and Drug Dependence; 64.022, Veterans Home Based Primary Care; and 64.024, VA Homeless Providers Grant and Per Diem Program.
The Secretary of Veterans Affairs, or designee, approved this document 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. Robert L. Nabors II, Chief of Staff, Department of Veterans Affairs, approved this document on October 9, 2015, for publication.
Administrative practice and procedure, Alcohol abuse, Alcoholism, Claims, Day care, Dental health, Drug abuse, Government contracts, Grant programs-health, Grant programs-veterans, Health care, Health facilities, Health professions, Health records, Homeless, Mental health programs, Nursing homes, Reporting and recordkeeping requirements, Travel and transportation expenses, Veterans.
For the reasons set forth in the preamble, VA amends 38 CFR part 17 as follows:
38 U.S.C. 501, and as noted in specific sections.
The revisions and addition read as follows:
(a) A veteran must be enrolled in the VA health care system under § 17.36.
(b) * * *
(1) The veteran attempts, or has attempted, to schedule an appointment with a VA health care provider, but VA is unable to schedule an appointment for the veteran within:
(i) The wait-time goals of the Veterans Health Administration; or
(ii) With respect to such care or services that are clinically necessary, the period VA determines necessary for such care or services if such period is shorter than the wait-time goals of the Veterans Health Administration.
(4) * * *
(ii) Faces an unusual or excessive burden in traveling to such a VA medical facility based on geographical challenges, such as the presence of a body of water (including moving water and still water) or a geologic formation that cannot be crossed by road; environmental factors, such as roads that are not accessible to the general public, traffic, or hazardous weather; a medical condition that affects the ability to travel; or other factors, as determined by VA, including but not limited to:
(A) The nature or simplicity of the hospital care or medical services the veteran requires;
(B) The frequency that such hospital care or medical services need to be furnished to the veteran; and
(C) The need for an attendant, which is defined as a person who provides required aid and/or physical assistance to the veteran, for a veteran to travel to a VA medical facility for hospital care or medical services.
(a)
(d)
(i) Maintain at least the same or similar credentials and licenses as those required of VA's health care providers, as determined by the Secretary. The agreement reached under paragraph (b) of this section will clarify these requirements. Eligible health care providers must submit verification of such licenses and credentials maintained by the provider to VA at least once per 12-month period.
(ii) Not be excluded from participation in a Federal health care program (as defined in section 1128B(f) of the Social Security Act (42 U.S.C. 1320a-7b(f)) under section 1128 or 1128A of such Act (42 U.S.C. 1320a-7 and 1320a-7a)), not be identified as an excluded source on the list maintained in the System for Award Management or any successor system, and not be identified on the List of Excluded Individuals and Entities that is maintained by the Office of the Inspector General of the U.S. Department of Health and Human Services.
(2) Any entities that are eligible to provide care through the Program must ensure that any of their providers furnishing care and services through the Program meet the standards identified in paragraph (d)(1) of this section. An eligible entity may submit this information on behalf of its providers.
(e)
(1) A health care provider that is participating in a State Medicaid plan under title XIX of the Social Security Act (42 U.S.C. 1396
(2) An Aging and Disability Resource Center, an area agency on aging, or a State agency (as defined in section 102 of the Older Americans Act of 1965 (42 U.S.C. 3002)), or a center for independent living (as defined in section 702 of the Rehabilitation Act of 1973 (29 U.S.C. 796a)).
(3) A health care provider that is not identified in paragraph (e)(1) or (2) of this section, if that provider meets all requirements under paragraph (d) of this section.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Temporary rule; inseason General category bluefin tuna quota transfer and retention limit adjustment.
NMFS is transferring 80 metric tons (mt) of Atlantic bluefin tuna (BFT) quota from the Reserve category to the General category for the remainder of the 2015 fishing year. This transfer results in an adjusted 2015 General category quota of 646.7 mt. NMFS also is adjusting the Atlantic tunas General category BFT daily retention limit from four large medium or giant BFT per vessel per day/trip to three large medium or giant BFT per vessel per day/trip for the remainder of the 2015 fishing year. This action is based on consideration of the regulatory determination criteria regarding inseason adjustments and applies to Atlantic tunas General category (commercial) permitted vessels and Highly Migratory Species (HMS) Charter/Headboat category permitted vessels when fishing commercially for BFT.
Effective November 25, 2015 through December 31, 2015.
Sarah McLaughlin or Brad McHale, 978-281-9260.
Regulations implemented under the authority of the Atlantic Tunas Convention Act (ATCA; 16 U.S.C. 971
Earlier this year, NMFS implemented a final rule that increased the U.S. BFT quota and subquotas per ICCAT Recommendation 14-05 (80 FR 52198, August 28, 2015). The base quota for the General category is 466.7 mt. See § 635.27(a). Each of the General category time periods (January, June through August, September, October through November, and December) is allocated a portion of the annual General category quota. Although it is called the “January” subquota, the regulations allow the General category fishery under this quota to continue until the subquota is reached or March 31, whichever comes first. Based on the General category base quota of 466.7 mt, the subquotas for each time period are as follows: 24.7 mt for January; 233.3 mt for June through August; 123.7 mt for September; 60.7 mt for October through November; and 24.3 mt for December. Any unused General category quota rolls forward within the fishing year, which coincides with the calendar year, from one time period to the next, and is available for use in subsequent time periods. To date this year, NMFS has published four inseason quota transfers that have adjusted and distributed the available 2015 Reserve category quota among other quota categories (80 FR 7547, February 22, 2015; 80 FR 45098, July 29, 2015; 80 FR 46516, August 5, 2015; and 80 FR 68265, November 4, 2015). The Reserve category balance currently is 82.1 mt. The adjusted General category quota, following the four inseason actions, is 566.7 mt.
The 2015 General category fishery was open January 1, 2015, through March 31, 2015, reopened June 1, 2015, and remains open until December 31, 2015, or until the General category quota is reached, whichever comes first.
Under § 635.27(a)(9), NMFS has the authority to transfer quota among fishing categories or subcategories, after considering determination criteria provided under § 635.27(a)(8), including five new criteria recently added in Amendment 7. The determination criteria are: The usefulness of information obtained from catches in the particular category for biological sampling and monitoring of the status of the stock; the catches of the particular category quota to date and the likelihood of closure of that segment of the fishery if no adjustment is made; the projected ability of the vessels fishing under the particular category quota to harvest the additional amount of BFT before the end of the fishing year; the estimated amounts by which quotas for other gear categories of the fishery might be exceeded; effects of the adjustment on BFT rebuilding and overfishing; effects of the adjustment on accomplishing the objectives of the fishery management plan; variations in seasonal distribution, abundance, or migration patterns of BFT; effects of catch rates in one area precluding vessels in another area from having a reasonable opportunity to harvest a portion of the category's quota; review of dealer reports, daily landing trends, and the availability of the BFT on the fishing grounds; optimizing fishing opportunity; accounting for dead discards, facilitating quota monitoring, supporting other fishing monitoring programs through quota allocations and/or generation of revenue; and support of research through quota allocations and/or generation of revenue.
NMFS has considered the determination criteria regarding inseason adjustments and their applicability to the General category fishery for the end of 2015, including, but not limited to, the following: Regarding the usefulness of information obtained from catches in the particular category for biological sampling and monitoring of the status of the stock, biological samples collected from BFT landed by General category fishermen and provided by tuna dealers continue to provide NMFS with valuable parts and data for ongoing scientific studies of BFT age and growth, migration, and reproductive status. Additional opportunity to land BFT would support the collection of a broad range of data for these studies and for stock monitoring purposes.
NMFS also considered the catches of the General category quota to date and the likelihood of closure of that segment of the fishery if no adjustment is made; the projected ability of the vessels fishing under the particular category quota to harvest the additional amount of bluefin tuna before the end of the fishing year; and the estimated amounts by which quotas for other gear categories of the fishery might be exceeded. General category landings in the winter BFT fishery, which typically begins in December or January each year, are highly variable and depend on availability of commercial-sized BFT to participants. Commercial-sized BFT
Without a quota transfer at this time, NMFS would have to close the 2015 General category fishery as the currently available General category quota would be reached shortly. As of November 20, 2015, the General category has landed approximately 550 mt, or 97 percent of its available 2015 quota of 566.7 mt. Overall, approximately 79 percent of the total of the commercial BFT subquotas for 2015 has been harvested. NMFS will need to account for 2015 landings and dead discards within the adjusted U.S. quota, consistent with ICCAT recommendations, and anticipates having sufficient quota to do that even with this transfer. This quota transfer would provide additional opportunities to harvest the U.S. bluefin quota without exceeding it, while preserving the opportunity for General category fishermen to participate in the winter BFT fishery.
Another principal consideration is the objective of providing opportunities to harvest the full annual U.S. BFT quota without exceeding it based on the goals of the 2006 Consolidated HMS FMP and Amendment 7, including to achieve optimum yield on a continuing basis and to optimize the ability of all permit categories to harvest their full BFT quota allocations. This transfer would be consistent with the quotas recently established and analyzed in the Atlantic bluefin tuna quota final rule (80 FR 52198, August 28, 2015) and with objectives of the 2006 Consolidated HMS FMP and amendments, and is not expected to negatively impact stock health or to affect the stock in ways not already analyzed in those documents.
Based on the considerations above, NMFS is transferring 80 mt of Reserve category quota to the General category for the remainder of 2015, resulting in adjusted General and Reserve category quotas for 2015 of 646.7 mt and 2.1 mt, respectively. NMFS will close the 2015 General category fishery when the adjusted General category quota of 646.7 mt has been reached, or it will close automatically on December 31, 2015.
Under § 635.23(a)(4), NMFS may increase or decrease the daily retention limit of large medium and giant BFT over a range of zero to a maximum of five per vessel based on consideration of the relevant criteria provided under § 635.27(a)(8), and listed above. For the 2015 fishing year, NMFS adjusted the daily retention limit from the default level of one large medium or giant BFT to three large medium or giant BFT for the January subquota period (79 FR 77943, December 29, 2014), which closed March 31, 2015; and four large medium or giant BFT for the June through August period (80 FR 27863, May 15, 2015) as well as the September, October through November, and December periods (80 FR 51959, August 27, 2015). NMFS has considered the relevant criteria and their applicability to the General category BFT retention limit for the remainder of the fishing year. These considerations include, but are not limited to, the following:
Regarding the usefulness of information obtained from catches in the particular category for biological sampling and monitoring of the status of the stock, additional opportunity to land bluefin tuna would support the collection of a broad range of data for the biological studies and for stock monitoring purposes. Regarding the effects of the adjustment on BFT rebuilding and overfishing and the effects of the adjustment on accomplishing the objectives of the fishery management plan, this action would be taken consistent with the previously implemented and analyzed quotas, and it is not expected to negatively impact stock health or otherwise affect the stock in ways not previously analyzed. It is also supported by the Environmental Analysis for the 2011 final rule regarding General and Harpoon category management measures, which established the current range over which NMFS may set the General category daily retention limit (
Based on these considerations, NMFS has determined that a three-fish General category retention limit is warranted for the remainder of the year. It would provide a reasonable opportunity to harvest the U.S. quota of BFT without exceeding it, while maintaining an equitable distribution of fishing opportunities, help optimize the ability of the General category to harvest its available quota, allow collection of a broad range of data for stock monitoring purposes, and be consistent with the objectives of the 2006 Consolidated HMS FMP and amendments. Therefore, NMFS adjusts the General category retention limit from four to three large medium or giant BFT per vessel per day/trip, effective November 25, 2015 through December 31, 2015.
Regardless of the duration of a fishing trip, the daily retention limit applies upon landing. For example (and specific to the limit that will apply through the end of the year), whether a vessel fishing under the General category limit takes a two-day trip or makes two trips in one day, the day/trip limit of three fish applies and may not be exceeded upon landing. This General category retention limit is effective in all areas, except for the Gulf of Mexico, where NMFS prohibits targeted fishing for BFT, and applies to those vessels permitted in the General category, as well as to those HMS Charter/Headboat permitted vessels fishing commercially for BFT.
NMFS will continue to monitor the BFT fishery closely. Dealers are required to submit landing reports within 24 hours of a dealer receiving BFT. General, HMS Charter/Headboat, Harpoon, and Angling category vessel owners are required to report the catch of all BFT retained or discarded dead, within 24 hours of the landing(s) or end of each trip, by accessing
The Assistant Administrator for NMFS (AA) finds that it is impracticable and contrary to the public interest to provide prior notice of, and an opportunity for public comment on, this action for the following reasons:
The regulations implementing the 2006 Consolidated HMS FMP and amendments provide for inseason retention limit adjustments to respond to the unpredictable nature of BFT availability on the fishing grounds, the migratory nature of this species, and the regional variations in the BFT fishery. Affording prior notice and opportunity for public comment to implement the quota transfer and daily retention limit for the remainder of the year is impracticable as NMFS is reacting as quickly as possible to updated data and information that then requires
Delays in adjusting the retention limit may result in the available quota being met or exceeded and NMFS needing to close the fishery earlier than otherwise would be necessary under a lower limit. This could adversely affect those General and HMS Charter/Headboat category vessels that would otherwise have an opportunity to harvest BFT under retention limits set in response to the most recent data available. Limited opportunities to harvest the respective quotas may have negative social and economic impacts for U.S. fishermen that depend upon catching the available quota within the designated time periods. Adjustment of the retention limit needs to be effective as soon as possible, to extend fishing opportunities for fishermen in geographic areas with access to the fishery only during this time period. Therefore, the AA finds good cause under 5 U.S.C. 553(b)(B) to waive prior notice and the opportunity for public comment. For these reasons, there is good cause under 5 U.S.C. 553(d) to waive the 30-day delay in effectiveness.
This action is being taken under §§ 635.23(a)(4) and 635.27(a)(9), and is exempt from review under Executive Order 12866.
16 U.S.C. 971
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Final rule; fishing season notification.
This final rule establishes an opening date of January 1, 2016, for all Atlantic shark fisheries, including the fisheries in the Gulf of Mexico. This final rule also establishes the quotas for the 2016 fishing season based on over- and/or underharvests experienced during 2015 and previous fishing seasons. The large coastal shark (LCS) retention limit for directed shark limited access permit holders will start at 45 LCS other than sandbar sharks per trip in the Gulf of Mexico region and at 36 LCS other than sandbar sharks per trip in the Atlantic region. These retention limits for directed shark limited access permit holders may decrease or increase during the year to provide, to the extent practicable, fishing opportunities for commercial shark fishermen in all regions and areas. NMFS anticipates that the retention limit in the Atlantic region will likely increase to the default limit of 45 LCS other than sandbar sharks per trip around July 15, 2016, subject to NMFS' evaluation of the inseason trip limit adjustment criteria. These actions could affect fishing opportunities for commercial shark fishermen in the northwestern Atlantic Ocean, including the Gulf of Mexico and Caribbean Sea.
This rule is effective on January 1, 2016. The 2016 Atlantic commercial shark fishing season opening dates and quotas are provided in Table 1 under
Highly Migratory Species Management Division, 1315 East-West Highway, Silver Spring, MD 20910.
Guý DuBeck or Karyl Brewster-Geisz at 301-427-8503.
The Atlantic commercial shark fisheries are managed under the authority of the Magnuson-Stevens Fishery Conservation and Management Act (Magnuson-Stevens Act). The 2006 Consolidated Highly Migratory Species (HMS) Fishery Management Plan (FMP) and its amendments are implemented by regulations at 50 CFR part 635. For the Atlantic commercial shark fisheries, the 2006 Consolidated HMS FMP and its amendments established, among other things, commercial shark retention limits, commercial quotas for species and management groups, accounting measures for under- and overharvests for the shark fisheries, and adaptive management measures such as flexible opening dates for the fishing season and inseason adjustments to shark trip limits, which provide management flexibility in furtherance of equitable fishing opportunities, to the extent practicable, for commercial shark fishermen in all regions and areas.
On August 18, 2015 (80 FR 49974), NMFS published a rule proposing the 2016 opening dates for the Atlantic commercial shark fisheries and quotas, based on shark landings information reported as of July 15, 2015. The August 2015 proposed rule contains details that are not repeated here. The comment period on the proposed rule ended on September 17, 2015.
During the comment period, NMFS received several written and oral comments on the proposed rule. Those comments, along with the Agency's responses, are summarized below. As further detailed in the Response to Comments section, after considering all the comments, NMFS is opening the fishing seasons for all shark management groups on January 1, 2016, as proposed in the August 18, 2015, proposed rule. For directed shark limited access permit holders, the Gulf of Mexico blacktip, aggregated LCS, and hammerhead management groups will start the fishing season with a retention limit of 45 LCS other than sandbar sharks per vessel per trip. The aggregated LCS and hammerhead shark management groups in the Atlantic region will start the fishing season with a retention limit of 36 LCS other than sandbar sharks per vessel per trip for directed shark limited access permit holders, which is a change from the proposed rule. Also, some of the quotas have changed since the proposed rule, based on updated landings information as of October 16, 2015. The retention limit for incidental shark limited access permit holders has not changed and remains at 3 LCS other than sandbar sharks per trip and a combined total of 16 small coastal sharks (SCS) and pelagic sharks, combined, per trip, consistent with § 635.24(a)(3) and (4).
This final rule serves as notification of the 2016 opening dates of the Atlantic commercial shark fisheries and 2016 quotas, based on shark landings updated as of October 16, 2015, pursuant to the “opening commercial fishing season” criteria at § 635.27(b)(3)(i) through (vii). This action does not change the annual base commercial quotas established under the 2006 Consolidated HMS FMP and its amendments for any shark management group. Any such changes would be performed through a separate action. Rather, this action adjusts the annual base commercial quotas for 2016
NMFS received 6 written comments on the proposed rule from fishermen, dealers, and other interested parties. All written comments can be found at
After evaluating these criteria, as described in the proposed rule, and reviewing the public comments, NMFS has decided to open the fisheries in the Atlantic region with a lower retention limit than proposed. Specifically, on January 1, 2016, the LCS fisheries in the Atlantic region will open with a retention limit of 36 LCS other than sandbar sharks per vessel per trip for directed shark limited access permit holders. NMFS has determined that a lower retention limit at the start of the season will allow NMFS to more easily and closely monitor the quota and catch rates in the beginning of the year to help ensure equitable fishing opportunities later in the year. NMFS chose 36 LCS other than sandbar sharks per vessel per trip because that was the commercial retention limit for the fishery from 2013 through August 2015, and thus is familiar to both NMFS and the participants in the fishery.
The proposed rule stated that, if it appears that the quota is being harvested too quickly to allow fishermen throughout the entire region an opportunity to fish, NMFS will reduce the commercial retention limit after a portion of the quota is harvested (
After considering public comment, NMFS anticipates that it will increase the commercial retention limit around July 15, 2016, as this was the date used for prior season opening dates. The retention limit will be the default level of 45 LCS other than sandbar sharks per vessel per trip for directed shark limited access permit holders, or another amount, as deemed appropriate after considering the inseason trip limit adjustment criteria (§ 635.24(a)(8)).
Regarding the comments from constituents suggesting when to adjust the retention limit, NMFS intends to reduce the retention limit to 3 LCS other than sandbar sharks per vessel per trip if the quota is being caught too quickly (
Regarding the comments from the Commonwealth of Virginia Marine Resources Commission and other commenters requesting an opening date in June or July in order to allow state-water fishermen the opportunity to fish and regarding the comments from constituents who prefer a later start date in order to fish for sharks at the end of the year, NMFS agrees that the fishery should remain open later in the year and anticipates having the majority of the quota available after July 15, 2016. Based on past landings data, having the majority of the quota available after July 15 would allow Virginia state-water fishermen the opportunity to fish for sharks and potentially allow the fishery to be open in October through December. Regarding the comments that having the LCS fisheries in the Atlantic and Gulf of Mexico regions open at the same time will impact the market prices, NMFS has no control over the market prices and this is not one of the criteria NMFS evaluates when choosing an opening date. However, in the past, the LCS fisheries in the Atlantic and Gulf of Mexico regions have been open at the same time, and during those times, NMFS has not noticed any dramatic impacts on the ex-vessel prices in either region. For example, in 2013, when both regional LCS fisheries were open in January, the ex-vessel price for Atlantic aggregated LCS stayed consistent throughout the year and was much higher than the Gulf of Mexico aggregated LCS ex-vessel prices.
Regarding the comment relating to the different sub-regional opening dates, at this time, NMFS prefers to open both sub-regions at the same time to evaluate how the changes in the regulations, such as the increase in the retention limit, affect the fishery before making other changes to the commercial shark fishing season. NMFS may consider staggered opening dates for the sub-regions in future years if such an approach is needed to promote equitable fishing opportunities throughout the region.
NMFS considered a commercial retention limit for blacknose shark in Amendment 5a to the 2006 Consolidated HMS FMP (see Section 2.3, Alternatives Considered But Not Further Analyzed, of the Final Environmental Impact Statement for Amendment 5a) and received similar comments during the public comment period for Amendment 6. In those actions, NMFS preferred to address blacknose shark landings and discards by linking the blacknose shark and non-blacknose SCS quotas, which should provide a greater and more effective incentive for reducing landings of blacknose sharks than a retention limit, thus more effectively managing the blacknose fishery in a manner that maximizes resource sustainability, while minimizing, to the greatest extent possible, socioeconomic impacts. After the blacknose shark quota was reached much earlier this year (June 7) than in previous seasons (July 28, 2014, and September 30, 2013), NMFS examined the blacknose shark landings from the HMS electronic dealer data from 2015 on a per trip basis. These data indicate that the majority of the trips (60 percent of the total number of trips) landed less than 200 lb dw of blacknose sharks per trip; however, there were multiple trips (11 percent of the total number of trips) that landed more than 700 lb dw of blacknose sharks per trip, with some as high as 3,170 lb dw, which is approximately 8 percent of the entire quota. Because the blacknose shark linkage has caused the SCS fishery south of 34 degrees to close sooner than in previous seasons and given that the commercial quota continues to be overharvested, NMFS is re-considering the appropriateness of a commercial blacknose retention limit and may pursue this issue in a separate action.
NMFS made four changes to the proposed rule, as described below.
1. NMFS changed the final eastern Gulf of Mexico blacktip shark quota from the 28.9 mt dw (63,835 lb dw) in the proposed rule to 28.9 mt dw (63,819 lb dw), a difference of 16 lb dw, based on updated landings through October 16, 2015. In the 2016 shark season proposed rule (80 FR 49974; August 18, 2015), which was based on data available through July 17, 2015, the 2016 adjusted annual quota for eastern Gulf of Mexico blacktip shark was proposed to be 28.9 mt dw (63,835 lb dw), based on an underharvest of 0.1 mt dw (308 lb dw) from 2014 and an underharvest of 3.7 mt dw from 2015 (8,088 lb dw). NMFS explained in the proposed rule that it would adjust the proposed quotas based on dealer reports as of mid-October or mid-November 2015. Based on updated landings data through October 16, 2015, the overall 2015 Gulf of Mexico blacktip shark management group underharvest was 37.4 mt dw (82,373 lb dw). Consistent with Amendment 6 and the August 2015 proposed rule, NMFS will account for underharvest based on the sub-regional quota percentage split. Thus, the eastern Gulf of Mexico blacktip shark quota is increased by 9.8 percent of the 2015 underharvest or 3.7 mt dw (8,072 lb dw). Therefore, the 2016 adjusted annual quota for eastern Gulf of Mexico blacktip shark is 28.9 mt dw (63,819 lb dw) (25.1 mt dw annual base quota + 0.1 mt dw from 2014 underharvest + 3.7 mt dw from the 2015 underharvest = 28.9 mt dw). Landings
2. NMFS changed the final western Gulf of Mexico blacktip shark quota from the 266.6 mt dw (587,538 lb dw) in the proposed rule to 266.5 mt dw (587,396 lb dw), a difference of 142 lb dw, based on updated landings through October 16, 2015. In the proposed rule, which was based on data available through July 17, 2015, the 2016 adjusted annual quota for western Gulf of Mexico blacktip shark was proposed to be 266.6 mt dw (587,538 lb dw), based on an underharvest of 1.3 mt dw (2,834 lb dw) from 2014 and an underharvest of 33.7 mt dw (74,443 lb dw) from 2015. Based on updated landings data through October 16, 2015, the overall 2015 Gulf of Mexico blacktip shark management group was underharvested by 37.4 mt dw (82,373 lb dw). Consistent with Amendment 6 and the August 2015 proposed rule, NMFS will account for underharvest based on the sub-regional quota percentage split. Thus, the western Gulf of Mexico blacktip shark quota is increased by 90.2 percent of the 2015 underharvest, or 33.7 mt dw (74,301 lb dw). Therefore, the 2016 adjusted annual quota for eastern Gulf of Mexico blacktip shark is 266.5 mt dw (587,396 lb dw) (231.5 mt dw annual base quota + 1.3 mt dw from 2014 underharvest + 33.7 mt dw from the 2015 underharvest = 266.5 mt dw 2016 adjusted annual quota). As described above, landings information beyond October 16, 2015, was not available while NMFS was writing this rule. This final rule used the most recent available information to allow NMFS to properly analyze the fishery and open the fishery on January 1, 2016. Any landings between October 16 and December 31, 2015, will be accounted for in the 2017 shark fisheries quotas, as appropriate.
3. NMFS changed the final Atlantic blacknose shark quota from the 15.7 mt dw (34,700 lb dw) in the proposed rule to 15.7 mt dw (34,653 lb dw), a difference of 47 lb, based on updated landings through October 16, 2015. In the proposed rule, the quota for the Atlantic blacknose shark management group was proposed to be 15.7 mt dw (34,700 lb dw), due to an adjustment of 0.5 mt dw (1,111 lb dw) for a 2012 overharvest that was spread over five years and an adjustment of 1.0 mt dw (2,110 lb dw) for a 2015 overharvest that was spread over three years. However, based on the updated landings data, NMFS found that the 2015 quota was overharvested by 3.0 mt dw (6,471 lb dw) and not the 6,328 lb dw originally considered. Consistent with the proposed rule, NMFS will spread this overharvest amount over 3 years at 1.0 mt dw (2,157 lb dw) each year from 2016-2018. Thus, NMFS will reduce the 2016 base annual quota by 1.5 mt dw (3,268 lb dw), based on the 2012 overharvest amount and the most recent estimates of the 2015 landings. Therefore, the 2016 adjusted annual quota for Atlantic blacknose shark is 15.7 mt dw (34,653 lb dw) (17.2 mt dw annual base quota − 0.5 mt dw 2012 overharvest − 1.0 mt dw 2015 overharvest = 15.7 mt dw 2016 adjusted annual quota). As described above, landings information beyond October 16, 2015, was not available while NMFS was writing this rule. This final rule used the most recent available information to allow NMFS to properly analyze the fishery and open the fishery on January 1, 2016. Any landings between October 16 and December 31, 2015, will be accounted for in the 2017 shark fisheries quotas, as appropriate.
4. NMFS changed the retention limit for directed shark limited access permit holders at the start of the commercial shark fishing season for the aggregated LCS and hammerhead shark management groups in the Atlantic region from 45 LCS other than sandbar sharks per vessel per trip to 36 LCS other than sandbar sharks per vessel per trip. As explained above, NMFS changed the retention limit after considering the “opening commercial fishing season” criteria (§ 635.27(b)(3)), public comment, and the 2015 landings data in order to promote equitable fishing opportunities throughout the Atlantic region.
This final rule adjusts the 2016 commercial quotas due to over- and/or underharvests in 2015 and previous fishing seasons, based on landings data through October 16, 2015. The 2016 annual quotas by species and species group are summarized in Table 1. All dealer reports that are received by NMFS after October 16, 2015, will be used to adjust the 2017 quotas, if necessary. A description of the quota calculations is provided in the proposed rule and is not repeated here. Any changes are described in the “Changes from the Proposed Rule” section.
Based on the seven “opening commercial fishing season” criteria listed in § 635.27(b)(3), NMFS is opening all the 2016 Atlantic commercial shark fishing seasons on January 1, 2016 (Table 2).
Regarding the LCS retention limit, as shown in Table 2, for directed shark limited access permit holders, the Gulf of Mexico blacktip shark, aggregated LCS, and hammerhead shark management groups will start the commercial fishing season at 45 LCS other than sandbar sharks per vessel per trip, and the Atlantic aggregated LCS and hammerhead shark management groups will start the commercial fishing season at 36 LCS other than sandbar sharks per vessel per trip. In the Atlantic region, as described above, NMFS will closely monitor the quota at the beginning of the year. If it appears that the quota is being harvested too quickly to allow fishermen throughout the entire region an opportunity to fish (
All of the shark management groups will remain open until December 31, 2016, or until NMFS determines that the fishing season landings for any shark management group has reached, or is projected to reach, 80 percent of the available quota; however, consistent with § 635.28(b)(5), NMFS may close the Gulf of Mexico blacktip shark management group before landings reach, or are expected to reach, 80 percent of the quota. Additionally, NMFS has established non-linked and linked quotas; linked quotas are explicitly designed to concurrently close multiple shark management groups that are caught together to prevent incidental catch mortality from exceeding the total allowable catch. The linked and non-linked quotas are shown in Table 2. NMFS will file for publication with the Office of the Federal Register a notice of closure for that shark species, shark management group including any linked quotas, and/or region that will be effective no fewer than 5 days from date of filing. From the effective date and time of the closure until NMFS announces, via the publication of a notice in the
The NMFS Assistant Administrator has determined that the final rule is consistent with the 2006 Consolidated HMS FMP and its amendments, other provisions of the Magnuson-Stevens Act, and other applicable law.
This final rule is exempt from review under Executive Order 12866.
In compliance with section 604 of the Regulatory Flexibility Act (RFA), NMFS prepared a Final Regulatory Flexibility Analysis (FRFA) for this final rule, which analyzed the adjustments to the Gulf of Mexico blacktip shark, Gulf of Mexico aggregated LCS, and blacknose shark management group quotas based on over- and/or underharvests from the previous fishing season(s). The FRFA analyzes the anticipated economic impacts of the final actions and any significant economic impacts on small entities. The FRFA is below.
Section 604(a)(1) of the RFA requires an explanation of the purpose of the rulemaking. The purpose of this final rulemaking is, consistent with the Magnuson-Stevens Act and the 2006 Consolidated HMS FMP and its amendments, to establish the 2016 Atlantic commercial shark fishing quotas and fishing seasons. Without this rule, the Atlantic commercial shark fisheries would close on December 31, 2015, and would not open until another action was taken. This final rule will be implemented according to the regulations implementing the 2006 Consolidated HMS FMP and its amendments. Thus, NMFS expects few, if any, economic impacts to fishermen other than those already analyzed in the 2006 Consolidated HMS FMP and its amendments. While there may be some direct negative economic impacts associated with the opening dates for fishermen in certain areas, there could also be positive effects for other fishermen in the region. The opening dates were chosen to allow for an
Section 604(a)(2) of the RFA requires NMFS to summarize significant issues raised by the public in response to the Initial Regulatory Flexibility Analysis (IRFA), provide a summary of NMFS' assessment of such issues, and provide a statement of any changes made as a result of the comments. The IRFA was done as part of the proposed rule for the 2016 Atlantic Commercial Shark Season Specifications. NMFS did not receive any comments specific to the IRFA. However, NMFS received comments related to the overall economic impacts of the proposed rule, and those comments and NMFS' assessment of and response to them are summarized above (see Comments 1 and 3 above). As described in the responses to those comments relating to the season opening dates, consistent with § 635.27(b)(3), the opening date for the all of the commercial shark fisheries will be implemented as proposed (January 1, 2016).
Section 604(a)(4) of the RFA requires NMFS to provide an estimate of the number of small entities to which the rule would apply. The Small Business Administration (SBA) has established size criteria for all major industry sectors in the United States, including fish harvesters. The SBA size standards are $20.5 million for finfish fishing, $5.5 million for shellfish fishing, and $7.5 million for other marine fishing, for-hire businesses, and marinas (79 FR 33647; June 12, 2014). NMFS considers all HMS permit holders to be small entities because they had average annual receipts of less than $20.5 million for finfish-harvesting. The commercial shark fisheries are comprised of fishermen who hold shark directed or incidental limited access permits and the related shark dealers, all of which NMFS considers to be small entities according to the size standards set by the SBA. This final rule applies to the approximately 210 directed commercial shark permit holders (124 in the Atlantic and 86 in the Gulf of Mexico regions), 253 incidental commercial shark permit holders (153 in the Atlantic and 100 in the Gulf of Mexico regions), and 100 commercial shark dealers (71 in the Atlantic and 29 in the Gulf of Mexico regions) as of October 2015.
Section 604(a)(5) of the RFA requires NMFS to describe the projected reporting, recordkeeping, and other compliance requirements of the final rule, including an estimate of the classes of small entities which would be subject to the requirements of the report or record. None of the actions in this final rule would result in additional reporting, recordkeeping, or compliance requirements beyond those already analyzed in the 2006 Consolidated HMS FMP and its amendments.
Section 604(a)(6) of the RFA requires NMFS to describe the steps taken to minimize the economic impact on small entities, consistent with the stated objectives of applicable statutes. Additionally, the RFA (5 U.S.C. 603(c)(1)-(4)) lists four general categories of “significant” alternatives that would assist an agency in the development of significant alternatives that would accomplish the stated objectives of applicable statutes and minimize any significant economic impact of the rule on small entities. These categories of alternatives are: (1) Establishment of differing compliance or reporting requirements or timetables that take into account the resources available to small entities; (2) clarification, consolidation, or simplification of compliance and reporting requirements under the rule for such small entities; (3) use of performance rather than design standards; and (4) exemptions from coverage of the rule, or any part thereof, for small entities.
In order to meet the objectives of this rule, consistent with the Magnuson-Stevens Act, NMFS cannot exempt small entities or change the reporting requirements only for small entities because all the entities affected are small entities. Thus, there are no alternatives discussed that fall under the first, second, and fourth categories described above. NMFS does not know of any performance or design standards that would satisfy the aforementioned objectives of this rulemaking while, concurrently, complying with the Magnuson-Stevens Act; therefore, there are no alternatives considered under the third category.
This rulemaking does not establish management measures to be implemented, but rather implements previously adopted and analyzed measures as adjustments, as specified in the 2006 Consolidated HMS FMP and its amendments and the Environmental Assessment (EA) for the 2011 shark quota specifications rule (75 FR 76302; December 8, 2010). Thus, in this rulemaking, NMFS adjusted the base quotas established and analyzed in the 2006 Consolidated HMS FMP and its amendments by subtracting the underharvest or adding the overharvest, as specified and allowable in existing regulations. Under current regulations (§ 635.27(b)(2)), all shark fisheries close on December 31 of each year, or when NMFS determines that the fishing season landings for any shark management group has reached, or is projected to reach, 80 percent of the available quota, and do not open until NMFS takes action, such as this rulemaking to re-open the fisheries. Thus, not implementing these management measures would negatively affect shark fishermen and related small entities, such as dealers, and also would not provide management flexibility in furtherance of equitable fishing opportunities, to the extent practicable, for commercial shark fishermen in all regions and areas.
Based on the 2014 ex-vessel price, fully harvesting the unadjusted 2016 Atlantic shark commercial baseline quotas could result in total fleet revenues of $4,583,514 (see Table 3). For the Gulf of Mexico blacktip shark management group, NMFS has increased the baseline sub-regional quotas due to the underharvests in 2015. The increase for the eastern Gulf of Mexico blacktip shark management group could result in a $8,397 gain in total revenues for fishermen in that sub-region, while the increase for the western Gulf of Mexico blacktip shark management group could result in a $77,289 gain in total revenues for fishermen in that sub-region. For the Gulf of Mexico non-blacknose SCS management group, NMFS has reduced the baseline quota due to the overharvest in 2014. This will cause a potential loss in revenue of $7,571 for the fleet in the Gulf of Mexico region. For the Atlantic blacknose shark management group, NMFS will continue to reduce the baseline quota through 2018 to account for overharvest in 2012 and will reduce the baseline quota for the next 3 years to account for overharvest in 2015. These reductions will cause a potential loss in revenue of $3,203 for the fleet in the Atlantic region.
All of these changes in gross revenues are similar to the changes in gross revenues analyzed in the 2006 Consolidated HMS FMP and its amendments. The FRFAs for those amendments concluded that the economic impacts on these small entities are expected to be minimal. In the 2006 Consolidated HMS FMP and its amendments and the EA for the 2011 shark quota specifications rule, NMFS stated it would be conducting annual rulemakings and considering the potential economic impacts of adjusting the quotas for under- and overharvests at that time.
For this final rule, NMFS reviewed the “opening commercial fishing season” criteria at § 635.27(b)(3)(i) through (vii) to determine when opening each fishery will provide equitable opportunities for fishermen while also considering the ecological needs of the different species. Over- and/or underharvests of 2015 and previous fishing season quotas were examined for the different species/complexes to determine the effects of the 2016 final quotas on fishermen across regional fishing areas. The potential season lengths and previous catch rates were examined to ensure that equitable fishing opportunities would be provided to fishermen. Lastly, NMFS examined the seasonal variation of the different species/complexes and the effects on fishing opportunities. In addition to these criteria, NMFS also considered other relevant factors, such as recent landings data and public comments, before arriving at the final opening dates for the 2016 Atlantic shark management groups. For the 2016 fishing season, NMFS is opening all of the shark management groups on January 1, 2016. The direct and indirect economic impacts will be neutral on a short- and long-term basis for the Gulf of Mexico blacktip shark, Gulf of Mexico aggregated LCS, Gulf of Mexico hammerhead shark, Gulf of Mexico non-blacknose shark SCS, Atlantic non-blacknose shark SCS, Atlantic blacknose shark, sandbar shark, blue shark, porbeagle shark, and pelagic shark (other than porbeagle or blue sharks) management groups, because NMFS did not change the opening dates of these fisheries from the status quo.
Opening the aggregated LCS and hammerhead shark management groups in the Atlantic region on January 1 will result in short-term, direct, moderate, beneficial economic impacts, as fishermen and dealers in the southern portion of the Atlantic region will be able to fish for and sell aggregated LCS and hammerhead sharks starting in January. These fishermen will be able to fish earlier in the 2016 fishing season compared to the 2010, 2011, 2012, 2014, and 2015 fishing seasons, which did not start until June or July. Based on public comment, some Atlantic fishermen in the southern and northern part of the region prefer a January 1 opening for the fishery as long as the majority of the quota is available later in the year. With the implementation of the HMS electronic reporting system in 2013, NMFS now monitors the quota on a more real-time basis compared to the paper reporting system that was in place before 2013. This ability, along with the inseason retention limit adjustment criteria in § 635.24(a)(8), should allow NMFS the flexibility to further provide equitable fishing opportunities for fishermen across all regions, to the extent practicable. Depending on how quickly the quota is being harvested, NMFS will reduce the retention limits to ensure that fishermen farther north have sufficient quota for a fishery later in the 2016 fishing season. The direct impacts to shark fishermen in the Atlantic region of reducing the trip limit depend on the needed reduction in the trip limit and the timing of such a reduction. Therefore, such a reduction in the trip limit for directed shark limited access permit holders is only anticipated to have minor adverse direct economic impacts to fishermen in the short-term; long-term impacts are not anticipated as these reductions would not be permanent.
In the northern portion of the Atlantic region, a January 1 opening for the aggregated LCS and hammerhead shark management groups, with inseason trip limit adjustments to ensure quota is available later in the season, will have direct, minor, beneficial economic impacts in the short-term for fishermen as they will potentially have access to the aggregated LCS and hammerhead shark quotas earlier than in past seasons. Fishermen in this area have stated that, depending on the weather, some aggregated LCS species might be available to retain in January. Thus, fishermen will be able to target or retain aggregated LCS while targeting non-blacknose SCS. There will be indirect, minor, beneficial economic impacts in the short- and long-term for shark dealers and other entities that deal with shark products in this region as they will also have access to aggregated LCS products earlier than in past seasons. Thus, opening the aggregated LCS and hammerhead shark management groups in January and using inseason trip limit adjustments to ensure the fishery is open later in the year in 2016 will cause beneficial cumulative economic impacts, because it allows for a more equitable distribution of the quotas among constituents in this region, consistent with the 2006 Consolidated HMS FMP and its amendments.
Section 212 of the Small Business Regulatory Enforcement Fairness Act of 1996 states that, for each rule or group of related rules for which an agency is required to prepare a FRFA, the agency shall publish one or more guides to assist small entities in complying with the rule, and shall designate such publications as “small entity compliance guides.” The agency shall explain the actions a small entity is required to take to comply with a rule or group of rules. As part of this rulemaking process, NMFS has prepared a brochure summarizing fishery information and regulations for Atlantic shark fisheries for 2016. This brochure also serves as the small entity
16 U.S.C. 971
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Temporary rule; quota transfer.
NMFS announces that the State of North Carolina is transferring a portion of its 2015 commercial Atlantic bluefish quota to the State of New York. These quota adjustments are necessary to comply with the Bluefish Fishery Management Plan quota transfer provision. This announcement is intended to inform the public of the revised commercial quota for each state involved.
Effective November 30, 2015, through December 31, 2015.
Reid Lichwell, Fishery Management Specialist, 978-281-9112.
Regulations governing the bluefish fishery are found at 50 CFR part 648. The regulations require annual specification of a commercial quota that is apportioned among the coastal states from Florida through Maine. The process to set the annual commercial quota and the percent allocated to each state are described in § 648.162.
The final rule implementing Amendment 1 to the Bluefish Fishery Management Plan, which was published in the
North Carolina has agreed to transfer 250,000 lb (113,398 kg) of its 2015 commercial quota to New York. This transfer was prompted by state officials in New York to address an overage of its commercial bluefish quota and to provide sufficient quota to allow the fishery to remain open. The Regional Administrator has determined that the criteria set forth in § 648.162(e)(1) have been met. The revised bluefish quotas for calendar year 2015 are: North Carolina, 1,139,371 lb (512,727 kg); and New York, 1,094,304 lb (496,367 kg).
This action is taken under 50 CFR part 648 and is exempt from review under Executive Order 12866.
16 U.S.C. 1801
Nuclear Regulatory Commission.
Petition for rulemaking; notice of docketing.
The U.S. Nuclear Regulatory Commission (NRC) has received a petition for rulemaking (PRM) requesting that the NRC amend its “Domestic licensing of production and utilization facilities” regulations to require “installation of ex-vessel instrumentation for uninterruptible monitoring of coolant and fuel in reactors and spent-fuel pools.” The petition, dated September 10, 2015, was submitted by Dr. Alexander DeVolpi (the petitioner). The petition was docketed by the NRC on September 21, 2015, and was assigned Docket Number PRM-50-113. The NRC is examining the issues raised in this petition to determine whether they should be considered in rulemaking. The NRC is not requesting public comment on PRM-50-113 at this time.
The PRM is available on December 1, 2015.
Please refer to Docket ID NRC-2015-0230 when contacting the NRC about the availability of information for this petition. You may obtain publicly-available information related to this petition by any of the following methods:
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For technical questions contact Jennifer Tobin, Office of Nuclear Reactor Regulation, telephone: 301-415-2328, email:
The petitioner, Dr. Alexander DeVolpi, states that he “has had a substantial technical career starting in the late 1950s in reactor safety and engineering, having worked for and been funded by U.S. nuclear development and regulatory agencies.” The petitioner notes that he has carried out relevant research and development and published supportive technical papers and filed patent applications.
The petitioner requests that the NRC amend part 50 of title 10 of the
The petitioner requests that the NRC amend its regulations in 10 CFR part 50 to require “installation of ex-vessel instrumentation for uninterruptible monitoring of coolant and fuel in reactors and spent-fuel pools.” The petitioner cites a 2014 National Research Council report titled, “Lessons Learned from the Fukushima Nuclear Accident for Improving Safety of U.S. Nuclear Plants,” that gave high priority to recommendation 5.1A, which stated that greater “[a]ttention to availability, reliability, redundancy, and diversity of plant systems and equipment is specifically needed for . . . Instrumentation for monitoring critical thermodynamic parameters in reactors, containments, and spent fuel pools.”
The petitioner claims that requiring the “installation of ex-vessel instrumentation for uninterruptible monitoring of coolant and fuel in reactors and spent-fuel pools” might prevent or mitigate potential accidents at reactors and spent fuel pools. The petitioner asserts that the Three Mile Island accident “might have been prevented if realtime uninterruptible ex-vessel reactor water-level monitoring had been in place.” Furthermore, the petitioner notes that one or both of the Fukushima meltdowns “might have been delayed or averted if uninterruptible ex-vessel real-time reactor water-level monitoring had been in place and operating on self-contained low-current battery supplies.” The petitioner states that ex-vessel instrumentation “would provide autonomous and redundant
The NRC has determined that the petition meets the threshold sufficiency requirements for docketing a petition for rulemaking under 10 CFR 2.802, “Petition for rulemaking,” and the petition has been docketed as PRM-50-113. The NRC will examine the issues raised in PRM-50-113 to determine whether they should be considered in the rulemaking process.
For the Nuclear Regulatory Commission.
Board of Governors of the Federal Reserve System (Board).
Notice of proposed rulemaking with request for public comment.
The Board invites public comment on a proposed rule that would implement public disclosure requirements regarding the liquidity coverage ratio (LCR) of large, internationally active banking organizations and certain smaller, less complex banking organizations. The proposed rule would apply to all depository institution holding companies and covered nonbank companies that are required to calculate the LCR (covered companies). A covered company would be required to publicly disclose on a quarterly basis quantitative information about its LCR calculation, as well as a discussion of certain features of its LCR results. The proposed rule also would amend the LCR Rule to provide a full year for certain companies to come into compliance.
Comments on this notice of proposed rulemaking must be received by February 2, 2016.
When submitting comments, please consider submitting your comments by email or fax because paper mail in the Washington, DC area and at the Board may be subject to delay. You may submit comments, identified by Docket No. R-1525, RIN 7100 AE 39, by any of the following methods:
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All public comments are available from the Board's Web site at
Gwendolyn Collins, Assistant Director, (202) 912-4311, Peter Clifford, Manager, (202) 785-6057, Adam S. Trost, Senior Supervisory Financial Analyst, (202) 452-3814, J. Kevin Littler, Senior Supervisory Financial Analyst, (202) 475-6677, SoRelle Peat, Financial Analyst, (202) 452-2543, Risk Policy, Division of Banking Supervision and Regulation; Dafina Stewart, Counsel, (202) 452-3876, or Adam Cohen, Counsel, (202) 912-4658, Legal Division, Board of Governors of the Federal Reserve System, 20th and C Streets NW., Washington, DC 20551. For the hearing impaired only, Telecommunication Device for the Deaf (TDD), (202) 263-4869.
On September 3, 2014, the Board of Governors of the Federal Reserve System (Board), the Office of the Comptroller of the Currency, and the Federal Deposit Insurance Corporation (collectively, the agencies) adopted a final rule (LCR Rule) to implement a quantitative liquidity requirement, the liquidity coverage ratio
The LCR Rule applies to large and internationally active banking organizations, generally, (1) bank holding companies, certain savings and loan holding companies, and depository institutions that, in each case, have $250 billion or more in total consolidated assets or $10 billion or more in on-balance sheet foreign exposure; (2) depository institutions with $10 billion or more in total consolidated assets that are consolidated subsidiaries of such bank holding companies and savings and loan holding companies; and (3) nonbank financial companies designated by the Financial Stability Oversight Council for Board supervision to which the Board has applied the LCR Rule by rule or order. The LCR Rule also applies, via a final rule adopted by the Board (modified LCR Rule) that implemented a modified LCR requirement (modified LCR), to bank holding companies and certain savings and loan holding companies that, in each case, have $50 billion or more in total consolidated assets but that do not meet the threshold for large and internationally active firms (modified LCR holding companies). Community banking organizations are not subject to the LCR Rule.
One of the key lessons of the recent financial crisis was that market participants did not have adequate access to information about the liquidity risk profiles of large banking organizations. In the Supplementary Information to the LCR Rule, the agencies indicated their plans to seek comment on “instructions pertaining to a covered company's disclosure of the final rule's LCR.”
The proposed rule would apply to the following companies subject to the LCR Rule: (1) All bank holding companies and certain savings and loan holding companies that, in each case, have $250 billion or more in total consolidated assets or $10 billion or more in on-balance sheet foreign exposure; (2) nonbank financial companies designated by the Financial Stability Oversight Council for Board supervision to which the Board has applied the LCR Rule by rule or order (covered nonbank company);
The proposed rule would require a covered company to publicly disclose information about certain components of its LCR calculation in a standardized tabular format (LCR disclosure template) and discuss certain features of its LCR results.
Each of the proposed disclosure requirements is designed to highlight important aspects of a covered company's liquidity position. Public disclosure of information about covered company LCR calculations would help market participants and other parties consistently assess the liquidity risk profile of covered companies. In designing the proposed disclosure requirements, the Board has considered the burden of the proposed disclosures relative to the public interest served by requiring their disclosure. All the required quantitative disclosures reflect data that covered companies are already required to compute under the LCR Rule. Moreover, the disclosure requirements for a discussion of certain features of covered companies' LCR results largely reflect information that covered companies already should have prepared to meet the liquidity risk management standards and practices required by the agencies through other applicable liquidity regulations and described in guidance. The Board invites comment on all aspects of the proposed rule, including what changes, if any, could improve the clarity and utility of the disclosure.
As noted above, under the proposed rule, a covered company would be required to publicly disclose certain components of its LCR calculation in a standardized tabular format. The proposed standardized tabular format will help market participants compare the LCRs of covered companies across the U.S. banking industry and international jurisdictions.
The proposed LCR disclosure template is similar to a common disclosure template developed by the BCBS; however as discussed in more detail in sections II.A through II.D of this Supplementary Information, the proposed rule reflects differences between the LCR Rule and the Basel III Liquidity Framework.
The proposed rule includes a number of requirements designed to help ensure the comparability of data across companies. Under the proposed rule, a covered company would be required to calculate all disclosed amounts as simple averages of the components used to calculate its daily LCR over a quarterly reporting period, except that modified LCR holding companies would be required to calculate all disclosed amounts as simple averages of the components used to calculate their monthly modified LCR. In addition, a covered company would be required to calculate all disclosed amounts on a consolidated basis; express the results in millions of U.S. dollars or as a percentage, as applicable; and clearly indicate the date range covered by the disclosure by indicating the beginning and end-date of the reporting period on the LCR disclosure template. The proposed rule would require a covered company to disclose both average unweighted amounts and average
The proposed rule, like the BCBS common template, would require a covered company to disclose its average eligible HQLA.
The proposed rule would require the disclosure of both average unweighted amounts and average weighted amounts of eligible HQLA and each of its component levels of assets (
The proposed rule would require a covered company to disclose its cash outflows, including both the average unweighted amounts and average weighted amounts. This information is important to understand the ongoing funding risks facing a firm, and in particular, potential sources of strain during a 30 calendar-day period of market volatility. The average unweighted amounts of cash outflows would be calculated prior to applying the outflow rates specified in 12 CFR 249.32. The average weighted amounts of cash outflows would be calculated after the application of the outflow rates specified in 12 CFR 249.32.
The proposed disclosure requirements for cash outflows are consistent with the BCBS common template, with a few modifications. First, the proposed rule adjusts some of the cash outflow category titles from those in the BCBS common template for consistency with the terminology used in the LCR Rule. For example, the proposed rule would have an outflow title that includes “unconsolidated structured transactions” and “mortgage commitments” because those items are separate outflow provisions in the LCR Rule.
Second, in the Supplementary Information section of the LCR Rule, the agencies explained that certain types of retail brokered deposits could result in greater liquidity risks and, as a result, the LCR Rule provides outflow rates tailored to these types of retail brokered deposits in 12 CFR 249.32(g).
Third, the proposed rule would require disclosure of both the average unweighted and average weighted amounts of secured wholesale funding (
The proposed rule would require a covered company to disclose its cash inflows, including both average unweighted amounts and average weighted amounts. As with information regarding cash outflows, information regarding cash inflows is important to understand the ongoing funding risks facing a firm. Similar to the requirements for cash outflows, the average unweighted amounts of cash inflows would be calculated prior to applying the inflow rates specified in 12 CFR 249.33. The average weighted amounts of cash inflows would be calculated after the application of the inflow rates specified in 12 CFR 249.33.
The proposed disclosure requirements for cash inflows are similar to the BCBS common template, with a few modifications. As with outflows, the proposed rule adjusts some of the cash inflow category titles from those used in the BCBS common template to make the terminology consistent with the LCR Rule and to disaggregate certain categories. For instance, the proposed rule would require “net derivative cash inflow,” “securities cash inflow,” “broker-dealer segregated account inflow,” and “other cash inflow” amounts each to be disclosed separately. In contrast, these inflow amounts are aggregated in the BCBS common template.
The proposed rule would require a covered company to disclose its average HQLA amount, average total net cash outflow amount, and the average LCR as measured over the quarterly reporting period. A covered company's HQLA amount and total net cash outflow amount are the numerator and the denominator of the LCR, respectively, and thus, are important to help market participants and other parties understand the liquidity risk profile of a covered company and compare profiles across companies.
A covered company is required to calculate its HQLA amount pursuant to 12 CFR 249.21. The HQLA amount is equal to the covered company's eligible HQLA, minus the appropriate amount to comply with the caps on the inclusion of certain assets as specified in the LCR Rule.
A covered company is required to calculate its total net cash outflow amount pursuant to 12 CFR 249.30. In order to determine a covered company's total net cash outflow amount, the LCR Rule requires covered companies, except modified LCR holding companies, to calculate a maturity mismatch add-on under 12 CFR 249.30(b) to address liquidity risks posed by maturity mismatches between a covered company's outflows and inflows during the 30 calendar-day period.
Pursuant to § 249.63 of the modified LCR Rule (12 CFR 249.63) a modified LCR holding company is required to calculate its total net cash outflow by multiplying its net cash outflow by a factor of 0.7. Consistent with this calculation of the modified LCR, the proposed rule would require a modified LCR holding company to disclose its average cash outflows and inflows before applying the factor of 0.7, but to disclose its average total net cash outflow after applying the factor of 0.7.
Under the proposed rule, the average values disclosed for HQLA amount, total net cash outflow amount, and the LCR (rows 29, 32, and 33) may not equal the calculation of those values using component values reported in rows 1 through 28. This lack of equivalence is due to technical factors such as the application of the level 2 liquid asset caps, the total inflow cap, and for modified LCR holding companies, the application of the 0.7 factor to total net cash outflows. The application of the asset and inflow caps and modified LCR 0.7 factor may affect a covered company's LCR calculation in varying degrees across the calculation dates used to determine the average values that would be disclosed in rows 29, 32, and 33, and thus, would affect the averages for the HQLA amount, total net cash outflow amount, and the LCR. The proposed LCR disclosure template includes a footnote that would highlight this difference.
The proposed rule would require a covered company to provide a discussion of certain features of its LCR results, which is consistent with the BCBS disclosure standards. The discussion of a covered company's LCR results will facilitate an understanding by market participants and other parties of the covered company's LCR and certain components used to calculate its LCR. A covered company's discussion of its LCR results may include, but does not have to be limited to, the following items: (1) The main drivers of the LCR results; (2) changes in the LCR results over time; (3) the composition of eligible HQLA; (4) concentration of funding sources; (5) derivative exposures and potential collateral calls; (6) currency mismatch in the LCR; (7) the covered company's centralized liquidity management function and its interaction with other functional areas of the covered company; and (8) other inflows and outflows in the LCR that are not specifically identified by the required quantitative disclosures, but that the covered company considers to be relevant to facilitate an understanding of its liquidity risk profile. The proposed rule also would require that a covered company provide a brief discussion of any significant changes that occur such that current or previous quantitative disclosures are no longer reflective of a covered company's current liquidity risk profile.
The proposed rule would require a covered company to provide timely public disclosures after each calendar quarter. Disclosure on a quarterly basis is appropriate to meet the objectives of the public disclosure requirements by providing information that will help market participants and other parties assess the liquidity risk profiles of covered companies over the previous quarter while not destabilizing covered companies, which could occur with more frequent public disclosure such as daily disclosure. The Board acknowledges that the timing of disclosures under the federal banking laws may not always coincide with the timing of disclosures required under other federal law, including disclosures required under the federal securities laws and their implementing regulations by the Securities and Exchange Commission (SEC). For calendar quarters that do not correspond to a covered company's fiscal year-end, the Board would consider those disclosures that are made within 45 days of the end of the calendar quarter (or within 60 days for the limited purpose of the covered company's first reporting period in which it is subject to the proposed rule's disclosure requirements) as timely. In general, where a covered company's fiscal year-end coincides with the end of a calendar quarter, the Board considers disclosures to be timely if they are made no later than the applicable SEC disclosure deadline for the corresponding Form 10-K annual report. In cases where a covered company's fiscal year-end does not coincide with the end of a calendar quarter, the Board would consider the timeliness of disclosures on a case-by-case basis.
This approach to timely disclosures is consistent with the approach to public disclosures that the Board has taken in the context of other regulatory reporting and disclosure requirements. For example, the Board has used the same indicia of timeliness with respect to the public disclosures required under its regulatory capital rules.
For covered companies that currently are subject to the LCR Rule, the proposed effective dates for the proposed public disclosure requirements would differ based on the size, complexity, and potential systemic impact of those companies. The proposed rule would require covered companies that have $700 billion or more in total consolidated assets or $10 trillion or more in assets under custody and that are subject to the transition period in 12 CFR 249.50(a) to comply with the proposed public disclosure requirements beginning on July 1, 2016. Other covered companies (that are subject to the transition period in 12 CFR 249.50(b)) would be required to comply with the proposed public disclosure requirements on July 1, 2017. These proposed compliance dates would provide covered companies that are currently subject to the LCR Rule one year from the date that the covered companies are required to calculate their LCR on a daily basis to comply with the proposed public disclosure requirements. In addition, for modified LCR holding companies, the proposed rule would require the covered companies to comply with the public disclosure requirements on January 1, 2018. This proposed compliance date would provide modified LCR holding companies that are currently subject to the modified LCR Rule one year from the date that the modified LCR holding companies are required to calculate and maintain, on a monthly basis, an LCR equal to or greater than 1.0, to comply with the proposed public disclosure requirements.
For a covered company that becomes subject to the LCR Rule pursuant to 12 CFR 249.1(b)(2)(ii) after the effective date of the rule, the covered company would be required to make its first disclosures for the reporting period that starts on the date the company is required to begin to comply with the LCR Rule, which would be three months
For a modified LCR holding company that becomes subject to the modified LCR Rule after the rule's effective date, subpart G of the rule currently applies on the first day of the first quarter after which the company's total consolidated assets equal $50 billion or more. This compliance date may not provide sufficient time for these companies to build the systems required to calculate the modified LCR. In light of this operational challenge, the Board proposes to amend the modified LCR Rule to provide these companies with a full year to come into compliance with the rule.
Section 722 of the Gramm-Leach Bliley Act
• Has the Board organized the material to suit your needs? If not, how could this material be better organized?
• Are the requirements in the proposed rule clearly stated? If not, how could the proposed rule be more clearly stated?
• Does the proposed rule contain language or jargon that is not clear? If so, which language requires clarification?
• Would a different format (grouping and order of sections, use of headings, paragraphing) make the proposed rule easier to understand? If so, what changes to the format would make the proposed rule easier to understand?
• What else could the Board do to make the regulation easier to understand?
The Regulatory Flexibility Act
As discussed above, the proposed rule would establish a public disclosure requirement for the LCR applicable to all top-tier depository institution holding companies and nonbank financial companies required to calculate the LCR. The proposed rule would require a covered company to publicly disclose on a quarterly basis quantitative information about certain components of its LCR calculation in a standardized tabular format and a discussion of certain features of its LCR results.
Under regulations issued by the Small Business Administration, a “small entity” includes a depository institution, bank holding company, or savings and loan holding company with total assets of $550 million or less (a small banking organization). As of June 30, 2015, there were approximately 628 small state member banks, 3,676 small bank holding companies, and 257 small savings and loan holding companies.
The proposed rule would not apply to “small entities” and would apply only to (1) bank holding companies and certain savings and loan holding companies that, in each case, have $250 billion or more in total consolidated assets or $10 billion or more in on-balance sheet foreign exposure and (2) nonbank financial companies designated by the Financial Stability Oversight Council for Board supervision to which the Board has applied the LCR Rule by rule or order. The proposed rule also would apply to bank holding companies and certain savings and loan holding companies with $50 billion or more in total consolidated assets, which are subject to the modified LCR Rule. Companies that are subject to the proposed rule therefore substantially exceed the $550 million asset threshold at which a banking entity is considered a “small entity” under SBA regulations.
As noted above, because the proposed rule is not likely to apply to any company with assets of $550 million or less, if adopted in final form, it is not expected to apply to any small entity for purposes of the RFA. The Board is aware of no other Federal rules that duplicate, overlap, or conflict with the proposed rule. In light of the foregoing, the Board does not believe that the proposed rule, if adopted in final form, would have a significant economic impact on a substantial number of small entities supervised and therefore believes that there are no significant alternatives to the proposed rule that would reduce the economic impact on small banking organizations supervised by the Board.
The Board welcomes comment on all aspects of its analysis. A final regulatory flexibility analysis will be conducted after consideration of comments received during the public comment period.
Certain provisions of the proposed rule contain “collection of information” requirements within the meaning of the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501-3521). In accordance with the requirements of the PRA, the Board may not conduct or sponsor, and the respondent is not required to respond to, an information collection unless it displays a currently valid
Comments are invited on:
(a) Whether the collections of information are necessary for the proper performance of the Board's functions, including whether the information has practical utility;
(b) The accuracy of the estimates of the burden of the information collections, including the validity of the methodology and assumptions used;
(c) Ways to enhance the quality, utility, and clarity of the information to be collected;
(d) Ways to minimize the burden of the information collections 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.
All comments will become a matter of public record. Commenters may submit comments on aspects of this notice that may affect burden estimates at the addresses listed in the
A covered company must publicly disclose the information required under subpart J beginning on July 1, 2016, if the covered company is subject to the transition period under § 249.50(a) or July 1, 2017, if the covered company is subject to the transition period under § 249.50(b). For modified LCR holding companies, the proposed rule would require them to comply with the public disclosure requirements beginning on January 1, 2018.
Under the proposed rule, quantitative disclosures will convey information about a covered company's high-quality liquid assets and short-term cash flows, thereby providing insight into a covered company's liquidity risk profile. Consistent with the BCBS common template, the proposed rule would require a covered company to disclose both average unweighted amounts and average weighted amounts for the covered company's HQLA, cash outflow amounts, and cash inflow amounts. A covered company would also be required to calculate all disclosed amounts as simple averages of the components used to calculate its daily LCR over a quarterly reporting period, except that modified LCR holding companies would be required to calculate all disclosed amounts as simple averages of the components used to calculate their monthly modified LCR. A covered company would be required to calculate all disclosed amounts on a consolidated basis and express the results in millions of U.S. dollars or as a percentage, as applicable.
In addition, the proposed rule would require a covered company to provide a discussion of certain features of its LCR results. A covered company's qualitative discussion may include, but does not have to be limited to, the following items: (1) The main drivers of the LCR results; (2) changes in the LCR results over time; (3) the composition of eligible HQLA; (4) concentration of funding sources; (5) derivative exposures and potential collateral calls; (6) currency mismatch in the LCR; (7) the covered company's centralized liquidity management function and its interaction with other functional areas of the covered company; and (8) other inflows and outflows in the LCR that are not specifically identified by the required quantitative disclosures, but that the covered company considers to be relevant to facilitate an understanding of its liquidity risk profile. The proposed rule also would require that a covered company provide a brief discussion of any significant changes that occur such that current or previous quantitative disclosures are no longer reflective of a covered company's current liquidity risk profile.
Estimated Burden per Response: Reporting—0.25 hours; recordkeeping—10 hours and 100 hours; disclosure—24 hours.
Frequency: Reporting—monthly, quarterly, and annual; recordkeeping—annual; disclosure—quarterly.
Estimated Number of Respondents: 42.
Current Total Estimated Annual Burden: Reporting—13 hours; recordkeeping—1,140 hours.
Proposed Total Estimated Annual Burden: Reporting—13 hours; recordkeeping—1,140 hours; disclosure—4,032 hours.
Administrative practice and procedure; Banks, banking; Federal Reserve System; Holding companies; Liquidity; Reporting and recordkeeping requirements.
For the reasons stated in the preamble, the Board proposes to amend part 249 of chapter II of title 12 of the Code of Federal Regulations as follows:
12 U.S.C. 248(a), 321-338a, 481-486, 1467a(g)(1), 1818, 1828, 1831p-1, 1831o-1, 1844(b), 5365, 5366, 5368.
(c) * * *
(2) A Board-regulated institution that first meets the threshold for applicability of this subpart under
(a) Effective January 1, 2018, a covered depository institution holding company subject to this subpart must publicly disclose the information required under subpart J of this part each calendar quarter, except as provided in paragraph (b) of this section.
(b) Effective 18 months after a covered depository institution holding company first becomes subject to this subpart pursuant to § 249.60(c)(2), the covered depository institution holding company must provide the disclosures required under subpart J of this part each calendar quarter.
(a)
(b)
(2) A covered depository institution holding company or covered nonbank company subject to this subpart must provide the disclosures required by this subpart for the reporting period beginning on:
(i) July 1, 2016, and thereafter if the covered depository institution holding company is subject to the transition period under § 249.50(a); or
(ii) July 1, 2017, and thereafter if the covered depository institution holding company or covered nonbank holding company is subject to the transition period under § 249.50(b).
(3) A covered depository institution holding company or covered nonbank company that is subject to the minimum liquidity standard and other requirements of this part pursuant to § 249.1(b)(2)(ii), must provide the disclosures required by this subpart for the first reporting period beginning no later than the date they are first required comply with the requirements of this part pursuant to § 249.1(b)(2)(ii).
(c)
(d)
(a)
(b)
(A) On a consolidated basis and presented in millions of U.S. dollars or as a percentage, as applicable; and
(B) With the exception of amounts disclosed pursuant to paragraphs (c)(1), (5), (9), (14), (19), (23), and (28) of this section, as simple averages of daily calculations over a quarterly reporting period;
(ii) A covered depository institution holding company that is required to calculate its liquidity coverage ratio on a monthly basis pursuant to § 249.61, must calculate its disclosed average amounts as provided in paragraph (b)(1)(i) of this section, except that those amounts must be calculated as simple averages of monthly calculations over a quarterly reporting period;
(iii) A covered depository institution holding company or covered nonbank company subject to this subpart must disclose the beginning date and end date for each quarterly reporting period.
(2)
(ii) A covered depository institution holding company or covered nonbank company subject to this subpart must calculate the average unweighted amount of cash outflows and cash inflows before applying the outflow and inflow rates specified in §§ 249.32 and 249.33, respectively.
(3)
(ii) A covered depository institution holding company or covered nonbank company subject to this subpart must calculate the average weighted amount of cash outflows and cash inflows after applying the outflow and inflow rates specified in §§ 249.32 and 249.33, respectively.
(c)
(1) The sum of the average unweighted amounts and average weighted amounts reported under paragraphs (c)(2) through (4) of this section (row 1);
(2) The average unweighted amount and average weighted amount of level 1 liquid assets that are eligible HQLA under § 249.21(b)(1) (row 2);
(3) The average unweighted amount and average weighted amount of level 2A liquid assets that are eligible HQLA under § 249.21(b)(2) (row 3);
(4) The average unweighted amount and average weighted amount of level 2B liquid assets that are eligible HQLA under § 249.21(b)(3) (row 4);
(5) The sum of the average unweighted amounts and average weighted amounts of cash outflows reported under paragraphs (c)(6) through (8) of this section (row 5);
(6) The average unweighted amount and average weighted amount of cash outflows under § 249.32(a)(1) (row 6);
(7) The average unweighted amount and average weighted amount of cash outflows under § 249.32(a)(2) through (5) (row 7);
(8) The average unweighted amount and average weighted amount of cash outflows under § 249.32(g) (row 8);
(9) The sum of the average unweighted amounts and average weighted amounts of cash outflows reported under paragraphs (c)(10) through (12) of this section (row 9);
(10) The average unweighted amount and average weighted amount of cash outflows under § 249.32(h)(3) and (4) (row 10);
(11) The average unweighted amount and average weighted amount of cash outflows under § 249.32(h)(1), (2), and (5), excluding paragraph (h)(2)(ii) (row 11);
(12) The average unweighted amount and average weighted amount of cash outflows under § 249.32(h)(2)(ii) (row 12);
(13) The average unweighted amount and average weighted amount of cash outflows under § 249.32(j) and (k) (row 13);
(14) The sum of the average unweighted amounts and average weighted amounts of cash outflows reported under paragraphs (c)(15) and (16) of this section (row 14);
(15) The average unweighted amount and average weighted amount of cash outflows under § 249.32(c) and (f) (row 15);
(16) The average unweighted amount and average weighted amount of cash outflows under § 249.32(b), (d), and (e) (row 16);
(17) The average unweighted amount and average weighted amount of cash outflows under § 249.32(l) (row 17);
(18) The average unweighted amount and average weighted amount of cash outflows under § 249.32(i) (row 18);
(19) The sum of average unweighted amounts and average weighted amounts of cash outflows reported under paragraphs (c)(5), (9), (13), (14), (17), and (18) of this section (row 19);
(20) The average unweighted amount and average weighted amount of cash inflows under § 249.33(f) (row 20);
(21) The average unweighted amount and average weighted amount of cash inflows under § 249.33(c) (row 21);
(22) The average unweighted amount and average weighted amount of cash inflows under § 249.33(d) (row 22);
(23) The sum of average unweighted amounts and average weighted amounts of cash inflows reported under paragraphs (c)(24) through (27) of this section (row 23);
(24) The average unweighted amount and average weighted amount of cash inflows under § 249.33(b) (row 24);
(25) The average unweighted amount and average weighted amount of cash inflows under § 249.33(e) (row 25);
(26) The average unweighted amount and average weighted amount of cash inflows under § 249.33(g) (row 26);
(27) The average unweighted amount and average weighted amount of cash inflows under § 249.33(h) (row 27);
(28) The sum of average unweighted amounts and average weighted amounts of cash inflows reported under paragraphs (c)(20) through (23) of this section (row 28);
(29) The average amount of the HQLA amounts as calculated under § 249.21(a) (row 29);
(30) The average amount of the total net cash outflow amounts excluding the maturity mismatch add-on as calculated under § 249.30(a)(1) and (2) (row 30);
(31) The average amount of the maturity mismatch add-ons as calculated under § 249.30(b) (row 31);
(32) The average amount of the total net cash outflow amounts as calculated under § 249.30 or § 249.63, as applicable (row 32);
(33) The average of the liquidity coverage ratios as calculated under § 249.10(b) (row 33).
(d)
(i) The main drivers of the liquidity coverage ratio results;
(ii) Changes in the liquidity coverage ratio results over time;
(iii) The composition of eligible HQLA;
(iv) Concentration of funding sources;
(v) Derivative exposures and potential collateral calls;
(vi) Currency mismatch in the liquidity coverage ratio;
(vii) The centralized liquidity management function of the covered depository institution holding company or covered nonbank company and its interaction with other functional areas of the covered depository institution holding company or covered nonbank company; or
(viii) Other inflows, outflows, or other factors in the liquidity coverage ratio calculation that are not captured in the disclosures required by paragraph (b) of this section, but which the covered depository institution holding company or covered nonbank company considers to be relevant to facilitate an understanding of its liquidity risk profile.
(2) If a significant change occurs such that the disclosed amounts or previously disclosed amounts are no longer reflective of the current liquidity profile of the covered depository institution holding company or covered nonbank company, then the company must provide a brief discussion of this change and its likely impact.
Federal Trade Commission.
Request for public comments.
The Federal Trade Commission (“Commission”) requests public comment on the overall costs and benefits, and regulatory and economic impact, of its Rules and Regulations under the Trade Regulation Rule Concerning Preservation of Consumers' Claims and Defenses, commonly known as the “Holder Rule,” as part of the agency's regular review of all its regulations and guides.
Written comments must be received on or before February 12, 2016.
Interested parties may file a comment online or on paper, by following the instructions in the Request for Comment part of the
Stephanie Rosenthal (202) 326-3332, Bureau of Consumer Protection, Federal Trade Commission, 600 Pennsylvania Ave. NW., Washington, DC 20580.
On November 14, 1975, the Commission promulgated its Trade Regulation Rule concerning the Preservation of Consumers' Claims and Defenses. The Holder Rule protects consumers who enter into credit contracts with a seller of goods or services by preserving their right to assert claims and defenses against any holder of the contract, even if the original seller subsequently assigns the contract to a third-party creditor or assignee. It requires sellers that arrange for or offer credit to finance consumers' purchases to include the following Notice in their contracts:
ANY HOLDER OF THIS CONSUMER CREDIT CONTRACT IS SUBJECT TO ALL CLAIMS AND DEFENSES WHICH THE DEBTOR COULD ASSERT AGAINST THE SELLER OF GOODS OR SERVICES OBTAINED . . . WITH THE PROCEEDS HEREOF. RECOVERY HEREUNDER BY THE DEBTOR SHALL NOT EXCEED AMOUNTS PAID BY THE DEBTOR HEREUNDER.
The Commission periodically reviews all of its rules and guides. These reviews seek information about the costs and benefits of the agency's rules and guides, and their regulatory and economic impact. The information obtained assists the Commission in identifying those rules and guides that warrant modification or rescission. Therefore, the Commission now solicits comments on, among other things, the economic impact of and the continuing need for the Holder Rule; possible developments in the case law that need to be reflected in the Holder Rule; and the effect on the Holder Rule of any regulatory, technological, economic, or other industry changes.
The Commission solicits comment on the following specific questions related to the Holder Rule:
(1) Is there a continuing need for the Holder Rule as currently promulgated? Why or why not?
(2) What benefits has the Holder Rule provided to consumers? What evidence supports the asserted benefits?
(3) What modifications, if any, should the Commission make to the Holder Rule to increase its benefits to consumers?
(a) What evidence supports the proposed modifications?
(b) How would these modifications affect the costs and benefits of the Holder Rule for consumers?
(c) How would these modifications impact businesses, particularly small businesses?
(4) What impact has the Holder Rule had on the flow of truthful information to consumers and on the flow of deceptive information to consumers?
(5) What significant costs, if any, has the Holder Rule imposed on consumers? What evidence supports the asserted costs?
(6) What modifications, if any, should be made to the Holder Rule to reduce any costs imposed on consumers?
(a) What evidence supports your proposed modifications?
(b) How would these modifications affect the costs and benefits of the Holder Rule for consumers?
(c) How would these modifications affect the costs and benefits of the Holder Rule for businesses, particularly small businesses?
(7) What benefits, if any, has the Holder Rule provided to businesses, and in particular to small businesses? What evidence supports the asserted benefits?
(8) What modifications, if any, should be made to the Holder Rule to increase the benefits to businesses, and particularly to small businesses?
(a) What evidence supports your proposed modifications?
(b) How would these modifications affect the costs and benefits of the Holder Rule for consumers?
(c) How would these modifications affect the costs and benefits of the Holder Rule for businesses?
(9) What significant costs, if any, including costs of compliance, has the Holder Rule imposed on businesses, particularly small businesses? What evidence supports the asserted costs?
(10) What modifications, if any, should be made to the Holder Rule to reduce the costs imposed on businesses, and particularly on small businesses?
(a) What evidence supports your proposed modifications?
(b) How would these modifications affect the costs and benefits of the Rule for consumers?
(c) How would these modifications affect the costs and benefits of the Holder Rule for businesses?
(11) What evidence is available concerning the degree of industry compliance with the Holder Rule? Does this evidence indicate that the Rule should be modified? If so, why, and how? If not, why not?
(12) Are any of the Holder Rule's requirements no longer needed? If so, explain. Please provide supporting evidence.
(13) What modifications, if any, should be made to the Holder Rule to account for changes in relevant technology or economic conditions?
(a) What evidence supports the proposed modifications?
(b) How would these modifications affect the costs and benefits of the Holder Rule for consumers and businesses, particularly small businesses?
(14) Does the Holder Rule overlap or conflict with other federal, state, or local laws or regulations? If so, how?
(a) What evidence supports the asserted conflicts?
(b) With reference to the asserted conflicts, should the Holder Rule be modified? If so, why, and how? If not, why not?
(15) Are there foreign or international laws, regulations, or standards with respect to the products or services covered by the Holder Rule that the Commission should consider as it reviews the Holder Rule? If so, what are they?
(a) Should the Holder Rule be modified in order to harmonize with these foreign or international laws, regulations, or standards? If so, why, and how? If not, why not?
(b) How would such harmonization affect the costs and benefits of the Holder Rule for consumers and businesses, particularly small businesses?
You can file a comment online or on paper. For the Commission to consider your comment, we must receive it on or before February 12, 2016. Write “Holder Rule Review, FTC File No. P164800” on your comment. Your comment, including your name and your state, will be placed on the public record of this proceeding, including, to the extent practicable, on the public Commission Web site, at
Because your comment will be made public, you are solely responsible for making sure that your comment does not include any sensitive personal information, like anyone's Social Security number, date of birth, driver's license number or other state identification number or foreign country equivalent, passport number, financial account number, or credit or debit card number. You are also solely responsible for making sure that your comment does not include any sensitive health information, such as medical records or other individually identifiable health information. In addition, do not include any “[t]rade secret or any commercial or financial information which is . . . privileged or confidential,” as discussed in Section 6(f) of the FTC Act, 15 U.S.C. 46(f), and FTC Rule 4.10(a)(2), 16 CFR 4.10(a)(2). In particular, do not include competitively sensitive information such as costs, sales statistics, inventories, formulas, patterns, devices, manufacturing processes, or customer names.
If you want the Commission to give your comment confidential treatment, you must file it in paper form, with a request for confidential treatment, and you must follow the procedure explained in FTC Rule 4.9(c), 16 CFR 4.9(c). In particular, the written request for confidential treatment that accompanies the comment must include the factual and legal basis for the request, and must identify the specific portions of the comments to be withheld from the public record. Your comment will be kept confidential only if the FTC
Postal mail addressed to the Commission is subject to delay due to heightened security screening. As a result, we encourage you to submit your comments online. To make sure that the Commission considers your online comment, you must file it at
If you file your comment on paper, write “Holder Rule Review, FTC File No. P164800” on your comment and on the envelope, and mail it to the following address: Federal Trade Commission, Office of the Secretary, 600 Pennsylvania Avenue NW., Suite CC-5610 (Annex B), Washington, DC 20580, or deliver your comment to the following address: Federal Trade Commission, Office of the Secretary, Constitution Center, 400 7th Street SW., 5th Floor Suite 5610 (Annex B), Washington, DC 20024. If possible, submit your paper comment to the Commission by courier or overnight service.
Visit the Commission Web site at
By direction of the Commission.
Consumer Product Safety Commission.
Notice of proposed rulemaking; extension of comment period.
On September 8, 2015, the federal departments and agencies subject to the Federal Policy for the Protection of Human Subjects (referred to as the “Common Rule”) published a notice of proposed rulemaking (“NPR”) amending the Common Rule. Separately, on September 24, 2015, the Consumer Product Safety Commission (“CPSC” or “Commission”) proposed to adopt the Common Rule NPR by amending the Commission's regulations. The comment period for the Common Rule NPR is being extended; therefore, CPSC is extending the comment period for its proposed rule, accordingly.
The comment period for the CPSC's NPR published on September 24, 2015 (80 FR 57549), is extended by 30 days and thus will end on January 6, 2016.
You may submit comments, identified by docket ID number HHS-OPHS-2015-0008, by one of the following methods:
•
•
Comments received, including any personal information, will be posted without change to
Hope E. J. Nesteruk, Human Factors Engineer, Division of Human Factors, Directorate for Engineering Sciences, Consumer Product Safety Commission, 5 Research Place, Rockville, MD 20850; telephone: 301-987-2579; email:
Since the Common Rule NPR was published on September 8, 2015 (80 FR 53933), participating departments and agencies have received requests to extend the comment period to allow sufficient time for a full review of the proposed rule. Accordingly, the comment period for the Common Rule NPR published on September 8, 2015, has been extended and will end on January 6, 2016. Along with the other participating departments and agencies subject to the Common Rule, the CPSC provides notice that the comment period on the CPSC's NPR published on September 24, 2015 (80 FR 57549), has been extended to afford the public an additional opportunity to comment through the process set forth in the
Coast Guard, DHS.
Notice of study; request for comments.
U.S. Coast Guard Sector Miami received a study from the Florida Department of Environmental Protection, Southeast Florida Coral Reef Initiative (SEFCRI) concluding that the Miami Anchorage could be changed to reduce threats to protected coral and its habitat. The study indicated that the Miami Anchorage could be divided into two separate anchorage areas to reduce threats to protected coral while also facilitating the safe anchorage of shallow and deep draft vessels. The Coast Guard requests comments from interested persons regarding a possible modification of the Miami Anchorage based on the SEFCRI study.
All comments and related material must be received by the Coast Guard on or before February 1, 2016.
You may submit comments identified by docket number USCG-2015-0729 using the Federal eRulemaking Portal at
If you have questions about this document, call or email LT Ruth Sadowitz, Sector Miami Waterways Division Chief at 305-535-4307 or email at
South Florida is home to numerous threatened and endangered marine species, including hard and soft corals. These corals are routinely damaged by standard maritime activities such as anchoring. Damage to corals not only affects the survivability of individual corals but may have a cumulative impact on the marine ecosystem as a whole.
The Coast Guard establishes anchorage areas in order facilitate use of the navigable waterways by both recreational and commercial vessels. Anchorage areas ensure safe navigation, and protection of life and the environment. The Coast Guard previously established an anchorage area in the waters of the Atlantic Ocean, east of Miami Beach, Florida.
In 2008, the Florida Department of Environmental Protection, Southeast Florida Coral Reef Initiative (SECFRI) in coordination with the Anchorage Working Group (AWG) and the Coast Guard began working on methods to reduce damage to coral in the Miami Anchorage area. SECFRI completed a study indicating that it may be appropriate to change the Miami Anchorage area. The revision to the Miami Anchorage described below would break the anchorage into two authorized anchorage zones, a western anchorage and a larger eastern anchorage. We believe such a change would continue to ensure safe navigation in and around the Port of Miami while preserving imperiled species in the marine environment.
We encourage you to submit comments on the change to the Miami Anchorage area described in the SECFRI study. SECFRI's study will be available on the docket and can be accessed on the Federal eRulemaking Portal at
Please submit comments through the Federal eRulemaking Portal at
We accept anonymous comments. All comments received will be posted without change to
Please provide comments regarding the possible change listed below. In addition, please provide comments regarding potential impacts of this possible change and/or other concerns that you may have regarding the Miami Anchorage.
SECFRI's study concludes that the current Miami Anchorage established by coordinates in 33 CFR 110.188 (Atlantic Ocean off Miami and Miami Beach, FL) could be amended to mitigate threats to coral habitat and ensure that no vessels anchored in the area would damage protected coral bottom. The amended coordinates would establish two anchorages with a combined area of approximately 1.5 square miles and reduce the total anchorage area by approximately 3 square nautical miles. The amended anchorage areas would be established with the following coordinates:
This notice is issued under authority of 5 U.S.C. 552(a).
National Park Service, Interior.
Proposed rule; notice of determination.
The National Park Service proposes to amend the special regulations for Rocky Mountain National Park to allow bicycle use on a 2-mile segment of the East Shore Trail located within the park. A portion of this 2-mile segment will require trail construction activities to accommodate bicycles and is therefore considered a new trail that will be opened to bicycles. National Park Service regulations require promulgation of a special regulation to designate new trails for bicycle use off park roads and outside developed areas. National Park Service regulations require publication of notice in the
Comments on the proposed rule and the notice of determination must be received by 11:59 p.m. EST on February 1, 2016.
You may submit comments, identified by Regulation Identifier Number (RIN) 1024-AE31, by either of the following methods:
•
•
Larry Gamble, Chief of Planning and Compliance, Rocky Mountain National Park, 1000 U.S. Highway 36, Estes Park, CO 80517. Phone (970) 586-1320. Email:
Rocky Mountain National Park (park) was established in 1915 and is located in north central Colorado. The approximate 265,761-acre park contains spectacular scenery that includes majestic mountains, lakes, rivers, forests, meadows, and abundant wildlife. The East Shore Trail is an existing hiking trail that runs roughly north/south along the east shore of Shadow Mountain Lake near the town of Grand Lake, Colorado. The entire trail is 6.2 miles long and ends at the southern boundary of the park. The East Shore Trailhead is located south of the town of Grand Lake. The trailhead and the first 0.7 miles of the trail are located on land administered by the U.S. Forest Service as part of the Arapaho National Recreation Area. Bicycle use is currently permitted only on this 0.7-mile section of the trail. The remaining 5.5 miles of the East Shore Trail are located within the park. Hiking and fishing access to the lake are allowed along the trail. The proposed rule applies to the northernmost 2-mile segment of the East Shore Trail within the park extending north from Shadow Mountain Dam to the park boundary. Within this 2-mile segment, livestock (horses, mules, and llamas) are permitted on the northernmost 0.9 mile of the trail, which is also part of the Continental Divide National Scenic Trail. The 2-mile segment of the East Shore Trail corridor within the park is bounded on the west by Shadow Mountain Lake and on the east by designated wilderness.
In January 2014, the National Park Service (NPS) published the East Shore Trail Environmental Assessment (EA). The EA evaluates (i) the suitability of the trail for bicycle use; and (ii) life cycle maintenance costs, safety considerations, methods to prevent or minimize user conflict, and methods to protect natural and cultural resources and mitigate impacts associated with bicycle use on the trail. After a public review period, the Regional Director of the Intermountain Region signed a Finding of No Significant Impact (FONSI) in February 2015 that selected the preferred alternative (Alternative B) described in the EA.
At the same time that the Regional Director signed the FONSI, the Superintendent signed a written determination concluding that bicycle use on the 2-mile trail segment is consistent with the protection of the park area's natural, scenic and aesthetic values, safety considerations and management objectives, and would not disturb wildlife or park resources. This written determination is attached to the FONSI and appears on page 15 of that document. The FONSI concludes that a 1.75-mile section of the trail is an “existing trail” under 36 CFR 4.30 and that bicycle use on that section of the trail will have no significant impacts. Bicycle use therefore may be authorized on that section of the trail after the written determination is published in the
The EA, FONSI, and written determination, which contain a full description of the purpose and need for taking action, scoping, the alternatives considered, maps, and the environmental impacts associated with the project, may be viewed on the park's planning Web site at
This proposed rule would implement the selected action in the FONSI and authorize the Superintendent to designate bicycle use on a 2-mile segment of the East Shore Trail within the park. This segment of the trail extends north from Shadow Mountain Dam to the park boundary. To
The proposed rule would add a new paragraph (f) to section 7.7—Special Regulations, Areas of the National Park System for Rocky Mountain National Park. The proposed rule would require the Superintendent to notify the public of any designation of the trail for bicycle use through one or more of the methods listed in 36 CFR 1.7, and identify the designation on maps available in the office of the Superintendent and other places convenient to the public.
The rule would also authorize the superintendent to establish closures, conditions, or restrictions for bicycle use on designated routes in accordance with 36 CFR 4.30(f).
Executive Order 12866 provides that the Office of Information and Regulatory Affairs in the Office of Management and Budget will review all significant rules. The Office of Information and Regulatory Affairs has determined that this rule is not significant.
Executive Order 13563 reaffirms the principles of Executive Order 12866 while calling for improvements in the nation's regulatory system to promote predictability, to reduce uncertainty, and to use the best, most innovative, and least burdensome tools for achieving regulatory ends. The executive order directs agencies to consider regulatory approaches that reduce burdens and maintain flexibility and freedom of choice for the public where these approaches are relevant, feasible, and consistent with regulatory objectives. Executive Order 13563 emphasizes further that regulations must be based on the best available science and that the rulemaking process must allow for public participation and an open exchange of ideas. We have developed this rule in a manner consistent with these requirements.
This rule will not have a significant economic effect on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
This rule is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. This rule:
(a) Does not have an annual effect on the economy of $100 million or more.
(b) Will not cause a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions.
(c) Does not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises.
This rule does not impose an unfunded mandate on State, local, or tribal governments or the private sector of more than $100 million per year. The rule does not have a significant or unique effect on State, local or tribal governments or the private sector. It addresses public use of national park lands, and imposes no requirements on other agencies or governments. A statement containing the information required by the Unfunded Mandates Reform Act (2 U.S.C. 1531
This rule does not effect a taking of private property or otherwise have takings implications under Executive Order 12630. A takings implication assessment is not required.
Under the criteria in section 1 of Executive Order 13132, the rule does not have sufficient federalism implications to warrant the preparation of a Federalism summary impact statement. This proposed rule only affects use of federally-administered lands and waters. It has no outside effects on other areas. A Federalism summary impact statement is not required.
This rule complies with the requirements of Executive Order 12988. This rule:
(a) Meets the criteria of section 3(a) requiring that all regulations be reviewed to eliminate errors and ambiguity and be written to minimize litigation; and
(b) Meets the criteria of section 3(b)(2) requiring that all regulations be written in clear language and contain clear legal standards.
The Department of the Interior strives to strengthen its government-to-government relationship with Indian Tribes through a commitment to consultation with Indian tribes and recognition of their right to self-governance and tribal sovereignty. We have evaluated this rule under the criteria in Executive Order 13175 and under the Department's tribal consultation policy and have determined that tribal consultation is not required because the rule will have no substantial direct effect on federally recognized Indian tribes. Nevertheless, the NPS mailed a letter on April 18, 2013 inviting input specifically from affiliated Native American tribes and offering to arrange a site visit. No response was received.
This rule does not contain information collection requirements, and a submission to the Office of Management and Budget under the Paperwork Reduction Act is not required. We may not conduct or sponsor and you are not required to respond to a collection of information unless it displays a currently valid OMB control number.
We have prepared the EA to determine whether this rule will have a significant impact on the quality of the human environment under the National Environmental Policy Act of 1969. This rule would not constitute a major Federal action significantly affecting the quality of the human environment. A detailed statement under the National Environmental Policy Act is not required because we reached a FONSI. A copy of the EA and FONSI can be found online at
This rule is not a significant energy action under the definition in Executive Order 13211. A Statement of Energy Effects in not required.
We are required by Executive Orders 12866 (section 1(b)(12)) and 12988 (section 3(b)(1)(B)), and 13563 (section 1(a)), and by the Presidential Memorandum of June 1, 1998, to write all rules in plain language. This means that each rule we publish must:
(a) Be logically organized;
(b) Use the active voice to address readers directly;
(c) Use common, everyday words and clear language rather than jargon;
(d) Be divided into short sections and sentences; and
(e) Use lists and tables wherever possible.
If you feel that we have not met these requirements, send us comments by one of the methods listed in the
The primary authors of this regulation are Larry Gamble of Rocky Mountain National Park, Jay Calhoun, Regulations Program Specialist, National Park Service, and Andee Sears of the Alaska Regional Office.
It is the policy of the Department of the Interior, whenever practicable, to afford the public an opportunity to participate in the rulemaking process. Accordingly, interested persons may submit written comments regarding this proposed rule by one of the methods listed in the
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.
National parks, Reporting and Recordkeeping requirements.
In consideration of the foregoing, the National Park Service proposes to amend 36 CFR part 7 as set forth below:
54 U.S.C. 100101, 100751, 320102; Sec. 7.96 also issued under D.C. Code 10-137 and D.C. Code 50-2201.07.
(f)
Environmental Protection Agency (EPA).
Notice of public hearing.
The Environmental Protection Agency (EPA) is announcing a public hearing to be held for the proposed rule “Cross-State Air Pollution Rule Update for the 2008 Ozone NAAQS” which will publish in the
The public hearing will be held on December 17, 2015.
The public hearing will be held at the Environmental Protection Agency, William Jefferson Clinton East Building, Main Floor Room 1153, 1201 Constitution Avenue NW. in Washington, DC 20460. The public hearing will convene at 9:00 a.m. EST and continue until 8:00 p.m. EST or one hour after the last registered speaker has spoken, whichever is earlier. The EPA will make every effort to accommodate all speakers that arrive and register. Because this hearing is being held at a U.S. government facility, individuals planning to attend the hearing should be prepared to show valid picture identification to the security staff in order to gain access to the meeting room. No large signs will be allowed in the building, cameras may only be used outside of the building, and demonstrations will not be allowed on federal property for security reasons. The EPA Web site for the rulemaking, which includes the proposal and information about the public hearing, can be found at:
If you would like to present oral testimony at the public hearing, please register online at
Questions concerning the proposed “Cross-State Air Pollution Rule Update for the 2008 Ozone NAAQS” should be addressed to Mr. David Risley, U.S. EPA, Office of Atmospheric Programs, Clean Air Markets Division, (MS-6204 M), 1200 Pennsylvania Avenue NW.,
This public hearing provides the public with an opportunity to present oral comments regarding EPA's proposed Cross-State Air Pollution Rule Update for the 2008 Ozone NAAQS, which proposes Federal Implementation Plans that identify and limit emissions of nitrogen oxides in 23 eastern states that affect the ability of downwind states to attain and maintain compliance with the 2008 ozone national ambient air quality standard (NAAQS).
Commenters should notify Ms. Stevens if they will need specific equipment, or if there are other special needs related to providing comments at the hearings. The EPA will provide equipment for commenters to show overhead slides or make computerized slide presentations if we receive special requests in advance. Oral testimony will be limited to 5 minutes for each commenter. The EPA encourages commenters to provide EPA with a copy of their oral testimony electronically (via email or CD) or in hard copy form.
The hearing schedules, including lists of speakers, will be posted on EPA's Web site
EPA will make every effort to follow the schedule as closely as possible on the day of the hearing; however, please plan for the hearing to run either ahead of schedule or behind schedule.
The EPA has established a docket for the proposed “Cross-State Air Pollution Rule Update for the 2008 Ozone NAAQS” under Docket ID No. EPA-HQ-OAR-2015-0500 (available at
Environmental Protection Agency (EPA).
Proposed supplemental finding and request for comment.
The Environmental Protection Agency (EPA) is soliciting comment on a proposed supplemental finding that consideration of cost does not alter the agency's previous conclusion that it is appropriate and necessary to regulate coal- and oil-fired electric utility steam generating units (EGUs) under section 112 of the Clean Air Act (CAA). In light of the U.S. Supreme Court decision in
The EPA requests that you also submit a separate copy of your comments to the contact person identified below (see
The
In addition to being available in the docket, an electronic copy of this proposed supplemental finding will be available on the World Wide Web (WWW). Following signature, a copy of the proposed supplemental finding will be posted at the following address:
Please note that any updates made to any aspect of the hearing, including whether or not a hearing will be held, will be posted online at
Dr. Nick Hutson, Energy Strategies Group, Sector Policies and Programs Division (D243-01), U.S. EPA, Research Triangle Park, NC 27711; telephone number (919) 541-2968, facsimile number (919) 541-5450; email address:
The EPA is requesting comment on this proposed supplemental finding that including a consideration of cost does not alter the agency's previous determination that it is appropriate and necessary to regulate coal- and oil-fired EGUs under section 112 of the CAA. In light of the U.S. Supreme Court (Supreme Court) decision in
The EPA issued national emission standards for hazardous air pollutants (NESHAP) for coal- and oil-fired electric utility units, known as the Mercury and Air Toxics Standards or “MATS,” on February 16, 2012. Almost 12 years earlier, on December 20, 2000, the EPA determined, pursuant to CAA section 112(n)(1)(A), that it was appropriate and necessary to regulate coal- and oil-fired EGUs under CAA section 112 and added such units to the CAA section 112(c) list of sources that must be regulated under CAA section 112(d). (December 2000
On May 3, 2011, the EPA reaffirmed the 2000 appropriate and necessary finding and listing of EGUs, and proposed MATS pursuant to CAA section 112(d). 76 FR 24976. The EPA responded to comments on the appropriate and necessary finding, as well as the proposed MATS, and issued the final MATS on February 16, 2012. 77 FR 9304. Industry, states, environmental organizations, and public health organizations challenged many aspects of the EPA's appropriate and necessary finding and the final MATS rule in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court), and the Court denied all challenges.
The EPA, in response to the Supreme Court's direction, has now added consideration of cost to the appropriate and necessary finding as detailed in this document. In this document, the EPA concludes that including such consideration of cost does not alter the agency's previous determination that it is appropriate to regulate HAP emissions from EGUs. The agency is taking comment on the proposed supplemental finding through this document. The EPA is also taking comment on the supporting document “Legal Memorandum Accompanying the Proposed Supplemental Finding that it is Appropriate and Necessary to Regulate Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units (EGUs)” (Legal Memorandum) available in the docket for this action (EPA-HQ-OAR-2009-0234).
The regulated categories and entities potentially affected by this proposed supplemental notice are shown below in Table 1.
This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities that may be affected by this action. If you have any questions regarding the applicability of this action to a particular entity, consult either the air permitting authority for the entity or your EPA Regional representative as listed in 40 CFR 60.4 or 40 CFR 63.13 (General Provisions).
This action is in response to the Supreme Court's decision that the EPA must consider cost in the initial determination that regulation of HAP emissions from EGUs is appropriate under CAA section 112. In this document, the EPA provides detailed information on how the agency has taken cost into account in evaluating whether regulation of HAP from coal- and oil-fired electric utility steam generating units is appropriate and explains why the EPA proposes to find that including such consideration does not alter the previous determination. The EPA requests comment on this proposed supplemental finding and on the supporting Legal Memorandum available in the rulemaking docket (EPA-HQ-OAR-2009-0234).
The EPA is accepting comment only on the consideration of cost in making the appropriate determination and listing of EGUs. The analyses presented in this document and the Legal Memorandum in support of this document do not affect or alter other aspects of the appropriate and necessary interpretation or finding, or the CAA section 112(d) emission standards promulgated in MATS. These analyses also do not alter the Regulatory Impact Analysis (RIA) prepared for the final MATS. Specifically, the EPA is not
Also, the Supreme Court's decision neither calls into question nor reverses the portions of the D.C. Circuit Court's opinion unanimously rejecting all other challenges to the appropriate and necessary interpretation and finding and the HAP emission standards that the EPA promulgated in the final MATS rule. Industry, states, environmental organizations, and public health organizations challenged many aspects of the EPA's appropriate and necessary finding and the MATS emissions standards, including: (1) The EPA's reliance on the CAA section 112(c)(9) delisting criteria for determining the level of risk worth regulating; (2) the EPA's decision not to consider cost in making the appropriate and necessary determination and listing of EGUs; (3) the EPA's use of identified environmental harms as a basis for finding it appropriate and necessary to regulate HAP emissions from EGUs; (4) the EPA's consideration of the cumulative impacts of HAP emissions from EGUs and other sources in determining whether EGUs pose a hazard to public health or the environment; (5) the EPA's regulation of EGUs pursuant to CAA section 112(d) after adding EGUs to the section 112(c) list pursuant to the appropriate and necessary finding; (6) the EPA's determination that all HAP from EGUs should be regulated; (7) the EPA's technical basis for concluding that EGUs pose a hazard to public health or the environment; (8) the EPA's determination to regulate all EGUs as defined in CAA section 112(a)(8) in the same manner whether or not the individual units are located at major or area sources of HAP; (9) the EPA's emissions standards for mercury and acid gas HAP, including the EPA's decision not to set health based emission standards for acid gas HAP; (10) the EPA's use of certified data submitted by regulated parties; (11) the EPA's denial of a delisting petition filed by an industry trade group; (12) the EPA's decision not to subcategorize a certain type of EGU; and (13) the EPA's decision to allow EGUs to average HAP emissions among certain EGUs. The D.C. Circuit Court denied all challenges to the CAA section 112(n)(1)(A) appropriate and necessary finding and to the CAA section 112(d) MATS rule, and, with the exception of the cost issue relevant to the section 112(n)(1)(A) finding, all the challenges were unanimously rejected.
In addition, the EPA's citation to any final decision, interpretation, or conclusion in the MATS record does not constitute a re-opening of the issue or an invitation to comment on the underlying decision in which the EPA considered some cost of MATS (
It is worth noting that the issue addressed in this document—whether a consideration of cost alters the agency's previous determination that it is appropriate and necessary to regulate HAP emissions from coal- and oil-fired EGUs—goes to the listing of EGUs under CAA section 112. Under CAA section 112, such listing decisions are not final agency actions for purposes of judicial review. Instead, the public can comment on listing decisions during the CAA section 307(d) standard development process and challenge such decisions when the EPA issues final standards for a source category.
In the current action, the EPA adds a consideration of cost to the determination of whether it is appropriate to regulate HAP emissions from EGUs. As discussed in Sections III and IV.D of this document, it is the EPA's view that the consideration of cost in the appropriate finding should be weighed against, among other things, the volume of HAP emitted by EGUs and the associated hazards to public health and the environment. In this supplemental finding, therefore, the significant hazards to public health and the environment from HAP emitted by EGUs (and the substantial reductions in HAP emissions achieved by MATS that are described in Section IV.B.2 of this document) should be weighed against the costs of compliance.
As described in the peer-reviewed Mercury Study, mercury is a persistent, bioaccumulative toxic metal that can be emitted from coal-fired power plants in several chemical forms. Once deposited to water or land, mercury can be transformed into methylmercury (MeHg) by microbial action. MeHg is efficiently taken up by aquatic organisms and bioaccumulates in the aquatic food web. Larger predatory fish may have MeHg concentrations many times higher than, typically on the order of 1 million times, that of the concentrations in the freshwater body in which they live. Exposure to MeHg through ingestion of fish is the primary route for human exposures in the U.S. In 2000, the NAS Study reviewed the effects of MeHg on human health and concluded that mercury is highly toxic to multiple human and animal organ systems. Chronic low-dose prenatal exposure to MeHg from maternal consumption of fish has been associated with subtle neurotoxicity, which is manifest as poor performance on neurobehavioral tests, particularly on tests of attention, fine motor-function, language, and visual-spatial ability. The NAS concluded that the population at highest risk is the children of women who consumed large amounts of fish and seafood during pregnancy and that the risk to that population is likely to be sufficient to result in an increase in the number of children who have to struggle to keep up in school.
Exposure to high levels of the various non-mercury HAP (
In 2011, the EPA conducted additional technical analyses to support the appropriate and necessary finding reaffirmation, including peer-reviewed risk assessments on human health effects associated with mercury and non-mercury HAP emissions from EGUs, focusing on risks to the most exposed and sensitive individuals in the population. In addition, the EPA found that EGUs are by far the largest U.S. anthropogenic source of mercury, selenium, hydrogen chloride, and hydrogen fluoride emissions, and a significant source of metallic HAP emissions including arsenic, chromium, nickel, and others.
As explained above, the agency's conclusions regarding these public health and environmental hazards are not affected by the cost analyses presented in this document and comments on the hazard conclusions will be considered outside the scope of this action. However, it is critical to note that the EPA's conclusions regarding the public health and environmental hazards associated with emissions from EGUs form the primary basis for the agency's previous determinations that regulation of HAP emissions from coal- and oil-fired EGUs is appropriate and necessary.
In
In the Legal Memorandum, the EPA reevaluates the statute in light of the Supreme Court's holding in
The EPA's evaluation of CAA section 112 leads us to conclude that the purpose of that section of the CAA is to achieve prompt, permanent and ongoing reductions in HAP emissions from stationary sources to reduce the hazards to public health and the environment inherent in exposure to such emissions, with the goal of limiting the risk to the most exposed and most sensitive members of the population.
The EPA has also evaluated the specific section under which the appropriate and necessary determination is made—CAA section 112(n)(1)—to further inform our interpretation of the role of cost in making the appropriate determination under section 112(n)(1)(A).
CAA section 112(n)(1)(A) also does not dictate the manner in which cost is to be considered in the appropriate finding. In fact, the sole mention of cost in CAA section 112(n)(1) is the direction in section 112(n)(1)(B) to consider the costs of mercury controls. The statute thus gives the EPA discretion to identify a reasonable approach to incorporating cost into the analysis required under CAA section 112(n)(1)(A). In addition, because section 112(n)(1)(A) is a listing provision, the EPA must focus on
In determining whether it is appropriate to regulate HAP emissions from EGUs, the EPA concludes that it is reasonable to focus on whether the power sector can reasonably absorb the cost of compliance with MATS. The D.C. Circuit has previously provided general guidance on how to evaluate cost in the context of determining the reasonableness of New Source Performance Standards under section 111 of the CAA. The approach under CAA section 112 is somewhat different as section 112(d)(3) of the statute defines the minimum level of control based on levels that have been actually achieved by the best performing similar sources in the source category—a level deemed per se reasonable for other similar sources. Thus, the agency need not determine in the analysis the level of control that is technologically feasible and cost reasonable as is required when establishing standards under CAA section 111. Instead, the purpose of the cost analysis under CAA section 112(n)(1)(A) is to help evaluate whether the costs of regulation are reasonable when weighed against other relevant factors, most notably the identified hazards to public health and the environment from HAP emitted by EGUs that are reduced when the significant volume of HAP emission from EGUs is reduced. For EGUs, the reasonableness of the costs of CAA section 112(d) standards could be determined in part by an evaluation of this sector's ability to perform its primary and unique function—the generation, transmission and distribution of electricity. As explained below, the EPA considered several different cost metrics to evaluate whether cost of compliance with MATS are reasonable.
The statute also does not specify how much weight should be given to cost relative to other relevant factors. It thus provides the EPA discretion to develop reasonable approaches to considering
The EPA also concludes in the Legal Memorandum that a benefit-cost analysis is not required to support a threshold finding that regulation is appropriate. However, to the extent a benefit-cost analysis is used to evaluate whether regulation of HAP emissions from EGUs is appropriate, it is important to account for the full range of benefits associated with the action, including benefits that cannot be monetized due to lack of data. The statute does not require the EPA to compare only the monetized HAP-specific benefits to the compliance costs to support the finding. Neither does the statute direct the EPA to consider only the HAP benefits of the rule and ignore co-benefits, if the control strategies employed achieve multi-pollutant reductions. Instead, the EPA concludes that such an analysis would appropriately evaluate all of the known consequences of the rule. The Legal Memorandum concludes that the benefit-cost analysis in the RIA that accompanied the final MATS presents a reasonable evaluation of the costs and benefits of the final MATS rule.
The legal interpretations summarized above, and explained in greater detail in the Legal Memorandum, provide the basis for the evaluation of cost and conclusions presented in the remainder of this document. The EPA is requesting comment on all aspects of the Legal Memorandum and all conclusions contained therein.
This Section explains how the EPA has taken cost into account in evaluating whether regulation of coal- and oil-fired EGUs under section 112 of the CAA is appropriate. As the EPA explains above, and in the Legal Memorandum, there is little guidance in CAA section 112 on how the EPA could or should consider cost when making the threshold finding under CAA section 112(n)(1)(A) and the EPA has substantial discretion in identifying appropriate metrics for considering cost. The EPA has evaluated costs in this Section primarily through a consideration of whether the cost of compliance to the power sector is reasonable.
In Section IV.B below, the EPA discusses how it evaluated the reasonableness of the direct and indirect costs of the final CAA section 112(d) standards. As discussed earlier and in the Legal Memorandum, the EPA has substantial discretion in identifying appropriate metrics for considering cost. In evaluating how to appropriately consider costs, the EPA was mindful of Congress' statement regarding the 1990 CAA Amendments: “Our goal . . . has been to promote the public health and welfare and the productive capacity of our nation. We have given EPA both the regulatory tools to accomplish cleaner air and the flexibility to protect our industrial and productive capacity.”
The EPA has also identified other costs that help inform the agency's understanding of whether it is appropriate to regulate HAP emissions from EGUs. As discussed in the Legal Memorandum, the explicit reference to the cost of mercury controls in CAA section 112(n)(1)(B) and the reference to the availability of alternative control strategies in section 112(n)(1)(A) suggests that the EPA should consider the cost of controls for mercury and other HAP emitted from EGUs when determining whether regulation is appropriate.
Finally, while the EPA recognizes that cost is an important consideration in the determination of whether it is appropriate to regulate HAP emissions from EGUs, it is not the only consideration and CAA section 112(n)(1) does not support a conclusion that cost should be the predominant or overriding factor. As stated earlier, and detailed in the Legal Memorandum, the EPA must weigh the cost of compliance against other relevant factors—such as the advantages of regulation and achievement of statutory goals—in determining whether such consideration of cost causes the agency to alter its previous determination that it is appropriate to regulate HAP emissions from EGUs. This is discussed below in Section IV.D. As noted in Section I.C of this document, the public had ample opportunity to comment on all aspects of the MATS RIA, and the EPA responded to all of the significant comments.
In light of the statutory ambiguity regarding how to consider cost in making the appropriate and necessary finding, the EPA has exercised the discretion granted to it and applies several metrics relevant to the power sector to determine whether the estimated cost of compliance with MATS is reasonable. The EPA has also considered the reasonableness of the direct and indirect costs of compliance with MATS and the power sector's ability to maintain performance of its primary and unique function—the generation, transmission, and distribution of electricity.
As explained below, the EPA considered direct and indirect costs at the sector level because of the interconnectedness of the electricity grid and the fact that most power companies own diverse inventories of power generating units, including coal- and oil-fired EGUs. In this Section, the EPA has applied a number of different analyses (metrics) to assess whether the power sector's costs of compliance with the CAA section 112(d) standard is reasonable. Each of these analyses independently support a conclusion that the estimated costs of compliance with MATS are reasonable.
In 2012, the EPA reaffirmed the appropriate and necessary finding and established CAA section 112(d) standards, and, as part of that rulemaking, the EPA estimated the cost of compliance with the proposed and final MATS standards pursuant to Executive Orders 12866 and 13563 and other applicable statutes and executive orders. In this Section, the EPA is evaluating whether the costs of compliance with MATS is reasonable, based on the RIA cost estimates.
In the following Sections, the EPA presents the methodology used to estimate annual compliance costs for MATS. The EPA then evaluates the estimates of the total annual costs of compliance with the standards, including a focus on estimates of total annualized costs of compliance compared to power sector retail sales and a comparison of capital expenditures required under MATS to overall power sector capital expenditures. We also present analyses of the impacts these costs are projected to have on the power sector and its consumers, including estimates of impacts on the average retail price of electricity and the characteristics of the units choosing to retire as a result of MATS.
In this and the following Sections, we present compliance cost and impact estimates from the MATS RIA for the year of 2015 in the broader historical context of power sector trends. The analyses demonstrate that the projected costs and impacts of MATS requirements are reasonable.
We focus on the 2015 impacts presented in the RIA because these results represent the first year of compliance with the MATS rule, and those compliance cost estimates would be the most relevant to the threshold determination. As discussed later, of the years analyzed in the MATS RIA, the compliance costs are highest in 2015, and thus we focus on it here as a representation of the maximum impact. The analyses in the final MATS RIA represented the best forecast of cost and impacts available to the EPA when MATS was promulgated.
In accordance with guidance issued by the Office of Management and Budget (OMB)
In the MATS RIA, the power sector's “compliance costs” are estimated in IPM as the change in electric power generation costs between a base case without MATS and a policy case where the sector complies with the HAP emissions limits in the final MATS. The base case provides a future projection of the power sector in the absence of MATS, and serves as the baseline against which projections under policy cases are compared. The policy case examined in the MATS RIA introduces the requirements of the rule as constraints on affected EGUs, which results in new projections of power sector outcomes under MATS. In simple terms, these compliance costs are an estimate of the increased expenditures by the entire power sector to comply with the EPA's requirements while continuing to serve a given level of electricity demand. Therefore, the projected compliance cost estimate is not limited to the increase in expenditures by those EGUs directly affected by MATS, nor does it account for the ability of many electricity producers to reduce the costs they bear by passing along their costs to consumers of electricity through higher electricity prices.
The EPA notes that the projected compliance cost estimate represents the incremental costs to the entire power sector to generate electricity, not just the compliance costs projected to be borne by coal-fired and oil-fired EGUs regulated under MATS. EGUs operate interdependently within a large and complex system. While the MATS requirements are directed at a subset of EGUs in the power sector, the compliance actions of the MATS-regulated EGUs will affect production costs and revenues of other units due to fuel and electricity price changes. Furthermore, EGUs are often owned and operated by firms with multiple generating sources, many of which are not subject to MATS requirements. Therefore, limiting the consideration of costs only to those expenditures incurred by EGUs directly regulated by MATS, and not the other costs expended by their owners, would provide an incomplete assessment of the costs of the rule. Thus, analyses that compare system-wide (or sector-level) compliance cost impacts of MATS to sector-level economic indicators are appropriate for considering whether the power sector can absorb compliance costs, and do so without diminishing its ability to supply electricity. This approach is also consistent with the EPA's analytical objective to evaluate as best as is reasonable and possible all consequences of economically significant regulatory actions.
Using IPM, the EPA estimated the emissions reductions and annual incremental costs resulting from MATS, including the costs of installing and operating additional pollution controls, investments in new generation capacity, shifts between or amongst various fuels, and other actions associated with compliance. The EPA estimated that, relative to the base case, the final MATS rule would reduce annual emissions of mercury by 75 percent, hydrogen chloride by 88 percent, and fine particulate matter (PM
We compare annual compliance costs to electricity sales at the power sector-level, often called a sales test. The sales test is a frequently used indicator of potential impacts from compliance costs on regulated industries.
Table 2 presents the value of retail electricity sales from 2000 to 2011, based on information from the U.S. Energy Information Administration (EIA).
Revenues from retail electricity sales increased from $277.2 billion in 2000 to a peak of $356.6 billion in 2008 (an increase of 29 percent during this period). As would be expected, the general increase in sales (in dollar terms) over this time period is partly due to increases in electricity sales (in electricity sold) and increases in prices over the same time period. The $9.6 billion in annual compliance costs of MATS projected for 2015 would represent about 2.7 percent of 2011 power sector revenues from retail electricity sales. If retail sales were to return to their 2008 peaks, the annual compliance costs would also represent about 2.7 percent of sales. If retail electricity sales were to decline to 2000 levels, the estimated annual compliance costs for MATS would represent approximately 3.5 percent of retail sales. Thus, the projected annual compliance costs of MATS represent a small fraction of the value of overall sales.
After considering the potential costs of MATS in light of power sector sales, the EPA concludes that the costs to the power sector are reasonable. As noted above, the EPA is not accepting comments on the methods applied in the MATS RIA, but rather the agency requests comments on the use of incremental compliance costs from the MATS RIA results as a way to consider costs in the CAA section 112(n)(1)(A) determination.
Another way in which cost can be evaluated is by comparing the annual capital expenditures required by MATS to the range of variation in capital expenditures from year to year. Capital costs represent largely irreversible investments for firms that must be paid off regardless of future economic conditions, as opposed to other important variable costs, such as fuel costs, that may vary according to economic conditions and generation needs. Table 3 presents two sets of estimates for trends in the annual capital expenditures by the electric power sector. This information informs the second metric used to consider the costs of MATS to the power sector, namely a ratio of annual capital expenditures estimated to be needed for MATS compliance to historical power sector-level overall capital expenditures.
For power sector-level capital expenditures, the EPA relies on two sets of information. The first set of information is from the U.S. Census Bureau's Annual Capital Expenditures Survey. The second set of information is from information compiled by SNL, a private sector firm that provides data and analytical services. While each dataset has limitations, the estimates from each correspond to one another reasonably well. The annual sector-level capital expenditures reported by SNL are generally lower than the information from the Census Bureau. This is in part because SNL captures information on capital expenditures from Securities and Exchange Commission (SEC) filings, which are submitted by most but not by all entities in the power sector, whereas the U.S. Census Bureau's estimate of capital expenditures in the power sector is intended to capture capital expenditures for all entities in the power sector. For this reason, we present both sets of information to better depict capital expenditures in the power sector.
Capital expenditures generally increase from 2000 to 2011 but not in a linear fashion, partly a result of increased demand. In 2000, capital expenditures for the electric power sector are estimated to be $51.8 billion (based on SNL) and $62.5 billion (based on Census). Capital expenditures for this sector reached a low in 2004 at $40.4 billion (based on SNL) and $45.0 billion (based on Census), rising to their peak in 2011 at $79.6 billion (based on SNL) or in 2009 at $87.9 billion (based on Census).
The final MATS RIA estimated the incremental capital expenditures to be $2.4 billion for 2015, which represent about 3.0 percent of 2011 power sector-level capital expenditures using either SNL or Census information.
The increased capital expenditures estimated to be required under MATS represent a small fraction of the power sector's overall capital expenditures in recent years. Additionally, the EPA notes that the projected $2.4 billion in incremental capital costs is well within the range of annual variability over the 2000-2011 period. During this period, based on the Census information for example, the largest year-to-year decrease in power sector-level capital expenditures was $19.6 billion (from 2001 to 2002) and the largest year-to-year increase in power sector-level capital expenditures was $23.4 billion (from 2000 to 2001). This wide range indicates substantial year-to-year variability in industry capital expenditures, and the projected $2.6 billion increase in capital expenditures in 2015 projected under MATS falls well-within this variability. Similar results are found using the SNL information.
After considering the potential impacts of MATS on industry capital expenditures, the EPA concludes that the costs to the power sector are reasonable. As noted above, the EPA is not accepting comments on the methods applied in the MATS RIA, but rather the agency requests comments on the use of incremental compliance expenditures from the MATS RIA results as a way to
In electricity markets, costs imposed on utilities can be fully or partly passed through to consumers, which can result in increased retail electricity prices. Evaluating the projected effect on retail electricity prices against the variations in electricity prices from year to year therefore provides an additional way to evaluate the “cost” or impact of MATS, in this instance on electricity consumers, instead of on owners of EGUs in the power sector. Using data from the EIA, Table 4 presents trends in the average retail price of electricity for all sectors (residential, commercial, industrial, transportation, and other sectors) from 2000 to 2011. This information informs the comparison of the percent increase in retail electricity prices projected to result from MATS for 2015 to historical levels of variation in electricity prices.
While compliance costs and electricity prices are evaluated independently when considering whether it is appropriate to regulate steam-fired EGUs under MATS, they are not independent or separable economic indicators. The cause of higher electricity prices is the increase in expenditures by the power sector described earlier. Therefore, the electricity price impacts and the associated increase in electricity bills by consumers are not costs that are in addition to the compliance costs described earlier in this section, and, in fact, to the extent the compliance costs are passed on to electricity consumers, the costs to the EGU owners in the power sector are reduced.
The final RIA estimated that MATS would result in relatively small changes in the average retail price of electricity. Retail electricity prices for 2015 were projected to increase from 9.0 cents per kilowatt-hour on average in the base case to 9.3 cents per kilowatt-hour with MATS, an increase of about 3.1 percent. The regional price increases projected for MATS ranged from 1.3 percent to 6.3 percent. Four regions out of the 13 regions for which retail prices were estimated (encompassing all lower 48 states) were projected to have a higher percentage increase in prices than the national average increase of 3.1 percent. However, each of these four regions also has a price that is lower than the national average.
The EPA notes that the projected 0.3 cents per kilowatt-hour increase in national average retail electricity price under MATS is well within the range of annual variability over the 2000-2011 period. During this period, based on the EIA information, the largest year-to-year decrease in national average retail electricity price was −0.2 cents per kilowatt-hour (from 2001 to 2002) and the largest year-to-year increase in national average retail electricity price was 0.5 cents per kilowatt-hour (from 2005 to 2006). This wide range indicates substantial variability, and the 0.3 cents per kilowatt-hour increase in the national average retail electricity price under MATS is well-within normal historical fluctuations.
After considering the potential impacts of MATS on retail electricity prices, the EPA concludes that the estimated increase in electricity prices is within the historical range and is reasonable. In addition, because the increase in electricity prices is in part due to the ability of many EGUs to pass their costs on to consumers, the estimated MATS compliance costs discussed above are in fact less of a burden on owners of EGUs in the power sector. As noted above, the EPA is not accepting comments on the methods applied in the MATS RIA, but rather the agency requests comments on the use of average retail price increases from the MATS RIA results as a way to consider costs in the CAA section 112(n)(1)(A) determination.
The EPA believes the statutory concern with the cost of compliance expressed in CAA section 112(n)(1) can reasonably be tied to a concern with the ability of EGUs to comply with the ARP and other CAA requirements, as well as CAA section 112(d)(3) standards, while at the same time maintaining a reliable supply of electricity.
The MATS RIA reported projected net changes in generation capacity under MATS, as compared to the base case. Relative to the base case, about 4.7 gigawatts (GW) of additional coal-fired capacity was projected to retire by 2015
This analysis indicates that the vast majority of the generation capacity in the power sector directly affected by the requirements of MATS would be able to absorb the anticipated compliance costs and remain operational. In order to ensure that any retirements resulting from MATS would not adversely impact the ability of affected sources and electric utilities from meeting the demand for electricity, the EPA conducted an analysis of the impacts of projected retirements on electric reliability. These resource adequacy analyses found that reserve margins could be maintained over a three-year MATS compliance period indicating that reliability could be maintained as the power sector complied with MATS.
After considering the potential impacts of MATS on power sector generation capacity, the EPA concludes that the costs to the power sector are reasonable. As noted above, the EPA is not accepting comments on the methods applied in the MATS RIA, but rather the agency requests comments on the use of the MATS RIA results as a way to consider costs in the CAA section 112(n)(1)(A) determination and on the analyses (metrics used to assess whether the power sector's cost of compliance with the CAA section 112(d) standards are reasonable).
In this Section, the EPA considers the costs of MATS to the power sector from a variety of perspectives. First, the EPA estimates that the total projected cost of the MATS rule to the power sector in 2015 represents between 2.7 and 3.5 percent of annual electricity sales when compared to years from 2000 to 2011, a small fraction of the value of overall sales. Second, the EPA demonstrates that the projected capital expenditures in 2015 represent between 3.0 and 5.9 percent of total annual power sector capital expenditures when compared to years leading up to the finalization of the MATS rule. This investment by the power sector comprises a small percentage of the sector's historical annual capital expenditures on an absolute basis and also falls within the range of historical variability in such capital expenditures. Third, the EPA finds the projected average retail price increases are within the range of historical variability as well as lower than their peak on an absolute basis. The EPA has compared the projected national average retail electricity price for 2015 under MATS to the period from 2000 to 2011 and has shown that the projected increase in electricity rates of 0.3 cents/kWh for 2015 represents an increase of 3.1 percent, well within the range of retail price fluctuations over the 2000 to 2011 period. Finally, this analysis indicates that the vast majority of the generation capacity in the power sector would be able to absorb the anticipated compliance costs and remain operational and that the generating capacity the EPA estimated would retire as a result of the rule was generally older and less efficient than the capacity projected to operate.
The EPA judges each of these analyses to be appropriate bases for evaluating whether the costs to the power sector are reasonable. Having performed these analyses independently, the EPA concludes that every one of them supports its conclusion that costs are reasonable.
In addition to the cost considerations described in Section IV.B above, the EPA considered the cost of mercury controls consistent with the requirement in CAA section 112(n)(1)(B), and the cost of controls for other HAP emissions from EGUs. In addition, we discuss the cost of implementing the ARP because of its relationship to the inclusion of section 112(n)(1)(A) in the 1990 CAA Amendments. Below we first address the ARP and then the costs of mercury and other controls.
As explained above and in the MATS record, section 112(n)(1)(A) was added to the CAA in 1990 along with other significant revisions to section 112, and that provision requires the EPA to conduct the Utility Study and determine the hazards to public health reasonably anticipate to occur after imposition of the other requirements of the CAA. In addition to significantly revising section 112, the 1990 amendments to the CAA included the utility specific ARP. The ARP was established with the goal of reducing emissions of SO
As described below, the EPA first considers the cost of mercury control technologies, consistent with CAA section 112(n)(1)(B), focusing on information available at the time the agency issued the Mercury Report through the time the EPA reaffirmed the appropriate and necessary finding in 2011. The EPA then considers the cost of control technologies for non-mercury HAP, and the changes in those costs over time.
The Mercury Study estimated the potential cost of mercury controls for EGUs and other sources,
Pursuant to CAA section 112(n)(1)(B), the EPA completed the peer-reviewed Mercury Study in 1997, and it considered, among other things, the availability and cost of mercury controls. The EPA used the findings in the Mercury Study to develop the mercury-related findings contained in the Utility Study.
Based on data available at the time, detailed estimates of mercury control costs were developed for several model plants that represented electric power generation at coal-fired power plants. For the EGUs, the Mercury Study evaluated the costs of activated carbon injection and carbon filter beds at model plants with different pre-existing controls. The Mercury Study also described the potentially significant co-benefit control of mercury emissions by conventional SO
The agency also considered alternative control strategies that were available and effective in reducing HAP emissions from EGUs pursuant to CAA section 112(n)(1)(A). In fact, in the December 2000 Finding, the EPA stated that “the application of technologies used to control mercury emissions in conjunction with technologies used to control other pollutants, an approach called multi-pollutant control, can substantially reduce or offset the costs of HAP control.” 65 FR 79825, at 79828 (December 20, 2000). The EPA also discussed new methods in development to adsorb mercury onto injected particles (sorbents) so that the mercury could be more readily removed by PM controls.
The EPA similarly concluded in the MATS rule that there were available mercury controls (76 FR 25014), and the record reflects that mercury control costs have declined considerably since 2000.
The EPA considered the cost of controls for the non-mercury metal, acid gas, and organic HAP. In 1990, the types and costs of control technologies were generally known (
Concerning the cost of non-mercury controls, we considered flue gas desulfurization (FGD) controls that can effectively reduce acid gas HAP and can also reduce mercury and other non-mercury HAP to varying degrees based in part on control configuration (
In response to the Supreme Court's holding in
These conclusions, contained in the December 2000 Finding and the 2011 MATS rule
The EPA has now evaluated cost and considered cost in light of the other factors relevant to determining whether regulation of HAP emissions from EGUs is appropriate. Based on a consideration of these factors, the EPA concludes that the consideration of cost does not cause us to alter our determination that regulation of HAP emissions from EGUs is appropriate.
The EPA concludes above that the direct and indirect costs to the power sector to comply with the final MATS standards based on several different metrics. The EPA also concludes above that the costs of compliance with the CAA section 112(d) standards established in MATS are reasonable and do not jeopardize the power sector's ability to perform its primary and unique function—the generation, transmission and distribution of electricity.
The EPA has considered the conclusion that the costs of compliance with the final MATS rule are reasonable in conjunction with the other relevant factors to determine whether the cost of regulation causes us to conclude that, despite the advantages of regulation such as the progress regulation will make toward reducing the identified hazards to public health, it would not be appropriate to regulate HAP emissions from EGUs. Specifically, the EPA considered the cost in light the findings that mercury and non-mercury HAP from EGUs pose significant hazards to public health and the environment that will not be addressed through imposition of the other requirements of the CAA.
The EPA also considered the purpose of CAA section 112 to achieve prompt, permanent and ongoing reductions in the volume of HAP emissions that pose identified or inherent hazards to public health and the environment to reduce the risks posed by such emissions, including risks to the most exposed and most sensitive members of the population. The EPA considered the fact that absent regulation of HAP emissions from EGUs, such units would continue to emit significant volumes of HAP emissions without a need to reduce or even monitor such emissions. This is particularly problematic for persistent HAP such as mercury, which, once emitted, can be re-emitted in the future, and as a result continue to contribute to mercury deposition and associated health and environmental hazards.
Having considered all of the relevant factors, including cost, the EPA finds that the cost of compliance with CAA section 112(d) standards does not cause us to alter our determination that regulation of HAP emissions from EGUs is appropriate. Numerous independent metrics support the conclusion that MATS, the regulation promulgated by the EPA to address HAP emissions from EGUs, is reasonable. MATS makes significant progress toward implementing the statutory goals of reducing the inherent hazards associated with HAP emissions and to reduce the risks posed by such emissions, including risks to the most exposed and most sensitive members of the population. In light of the meaningful progress MATS makes towards the important statutory objectives, and the EPA's conclusion that its associate costs are reasonable and will not affect the power sector's ability to continue supplying reliable power, the EPA concludes that it is appropriate to regulate HAP emissions from EGUs after considering cost.
Moreover, many of the congressional concerns related to costs and regulatory burden on the power sector, which led to the inclusion of section 112(n)(1) in
Finally, the EPA considered the fact that CAA section 112(d) ensures that the MACT floor level of control is technologically feasible and presumptively cost reasonable because it is based on the level of control actually achieved by existing sources in the same category or subcategory. See Legal Memorandum, Section III. In addition, while the statute requires a minimum level of control, the EPA maintains discretion under CAA section 112(d) to minimize the cost of compliance, for example, through subcategorization and emissions averaging.
By adding cost considerations into the EPA's evaluation of whether regulation of HAP emissions from EGUs is appropriate, the EPA has corrected the deficiency identified by the Supreme Court in
As discussed above and in the Legal Memorandum, the EPA has discretion to determine the manner in which to consider cost under CAA section 112(n)(1). The EPA does not interpret CAA section 112(n)(1)(A) as requiring a formal benefit-cost analysis in which benefits are monetized and compared against the monetary costs of an action. Further, it is the EPA's judgment that a formal, monetized benefit-cost analysis is not the preferred approach for weighing the advantages and disadvantages of regulating HAP emissions from EGUs. See Section IV.D (setting forth the EPA's preferred approach to incorporating cost in the appropriate finding). However, a formal benefit-cost analysis was conducted in accordance with all relevant guidance and is presented in the final MATS RIA. In this Section, the EPA provides background on the benefit-cost approach and considers the results of the benefit-cost analyses developed for MATS. As explained herein, the final MATS RIA demonstrates that the benefits of the rule significantly outweighed the costs of the rule and thus fully and independently supports the EPA's proposed supplemental finding.
As noted in Section I.C of this document, the public had ample opportunity to comment on all aspects of the MATS RIA, including the benefits analysis, and the EPA responded to all of the significant comments.
The EPA developed RIAs for both the proposed and final MATS rule pursuant to Executive Orders 12866 and 13563, as well as other applicable statutes and executive orders. Among other requirements, these executive orders require agencies to assess the costs and benefits of significant regulatory actions with the recognition that some impacts are difficult to quantify. Agencies are also required to make a reasoned determination that the benefits of an action justify its costs. The final MATS RIA met these requirements and followed all applicable guidance documents by closely examining all of the important consequences of the rule and applying rigorous, peer-reviewed methods to calculate the monetized costs and benefits, when possible.
According to the EPA's guidance, the foundation of benefit-cost analysis is determining whether a policy's overall net benefits to society are positive.
In addition to interpreting CAA section 112(n)(1)(A) as not requiring a benefit-cost analysis, the EPA does not consider a formal, monetized benefit-cost analysis to be the preferred approach for weighing advantages and disadvantages under that section for several important policy reasons. First, it is well-recognized that some categories of benefits can be difficult to monetize,
Using peer-reviewed methods consistent with the agency's standard practices and the EPA's and OMB's guidance, the final MATS RIA found significant net benefits. As described in Section IV.B.2 of this document, the EPA estimated the changes in costs and emissions from MATS by using IPM to model the consequences of achieving the HAP emission limits on the power sector (specifically, for coal-fired EGUs). As described in the MATS RIA, the EPA evaluates the health benefits associated with these changes in emissions using a multi-step process. First, the EPA models the chemical transport of those emission reductions and the associated change in exposure. Next, the EPA estimates the number of specific health effects associated with the modeled exposure changes using relationships from health studies. Lastly, the EPA assigns a dollar value to those health effects based on the economic literature.
The EPA estimated in the final RIA that MATS would reduce annual emissions from EGUs of mercury by 75 percent, hydrogen chloride (a surrogate for all acid gas HAP) by 88 percent, and PM
In the MATS RIA, the EPA could only quantify and monetize a small subset of the health and environmental benefits attributable to reducing mercury emissions. Specifically, among neurodevelopmental effects, the EPA was only able to quantify and monetize IQ loss among a small subset of recreational fishers. The analyses the EPA conducted for this endpoint generated an estimate of $4 to $6 million annually, which reflects the dollar value of the reduction in IQ loss associated with changes in mercury exposure for typical recreational fishers who consume fish during pregnancy from the freshwater watersheds where the EPA had fish tissue data. While IQ loss is the only health effect that could be quantified and monetized, the EPA's independent Science Advisory Board noted that it is not the most potentially significant health effect associated with mercury exposure as other neurobehavioral effects, such as language, memory, attention, and other developmental indices, that are more responsive to mercury exposure.
Because the subset of mercury-only benefits that the EPA could quantify from MATS does not account for many of the important benefits associated with reducing HAP emissions from EGUs, it would be unreasonable to draw any conclusions from a comparison of the mercury-only benefits to the full costs of MATS. Instead, a complete benefit-cost comparison would account for all of the consequences of achieving the HAP emission limits (
As discussed above in Section IV.B, installing control technologies and implementing the compliance strategies necessary to reduce the HAP emissions directly regulated by the MATS rule also results in concomitant (co-benefit) reductions in the emissions of other pollutants such as directly emitted PM
Further, as discussed in the Legal Memorandum, CAA section 112(n)(1)(A) itself supports the inclusion of co-benefits because the statute directs the EPA to perform a study of the hazards to public health from HAP emissions from EGUs that are likely to remain after imposition of the other provisions of the CAA, including the ARP. In other words, Congress directed the EPA to consider the HAP co-benefits attributable to the regulation of SO
Although data and methodological limitations did not allow the EPA to calculate all of the benefits that would result from reducing HAP emissions, the benefits (monetized and non-monetized) of MATS are substantial and far outweigh the costs, thus, the benefit-cost analysis presented in the RIA for MATS fully and independently supports the EPA's determination that it is appropriate to regulate HAP emissions from EGUs. The EPA requests comments on this conclusion.
As directed by the Supreme Court, the EPA has now taken cost into account in evaluating whether it is appropriate to regulate coal- and oil-fired EGUs under section 112 of the CAA. As explained in Section IV of this document, the EPA considered the reasonableness of the direct and indirect compliance costs of MATS based on several metrics and weighed the cost of regulation with other factors relevant to a decision to regulate HAP emissions from EGUs. The EPA found based on that evaluation that including a consideration of cost does not cause the agency to alter its determination that regulation of HAP emissions from EGUs is appropriate. The EPA also found that other cost considerations further support this conclusion.
In addition, though the EPA does not view formal benefit-cost analysis as required to support the appropriate finding, the EPA conducted a formal benefit-cost analysis in the RIA for MATS and that analysis demonstrates that the monetized and non-monetized benefits of MATS are significant and far exceed the cost. The benefit-cost analysis thus supports the finding that it is appropriate to regulate HAP emissions from EGUs.
The EPA finds that the analysis set forth in Section IV of this document and the benefit-cost analysis in the RIA for MATS (and summarized in Section V) each provide independent support for a conclusion that regulation of HAP emissions from EGUs is appropriate. Based on these findings, the EPA proposes that the agency's previous determination that it is appropriate to regulate HAP emissions from EGUs under section 112(d) of the CAA is not altered by a consideration of cost and that coal- and oil-fired EGUs are properly listed pursuant to section 112(c).
This action is a significant regulatory action that was submitted to OMB for review because it “raises novel legal or policy issues arising out of legal mandates.” Any changes made in response to OMB recommendations have been documented in the docket. The EPA does not project any potential costs or benefits associated with this action.
This action does not impose an information collection burden under the PRA. There are no information collection requirements in this proposed action.
I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA. This action will not impose any requirements on small entities. The EPA does not project any potential costs or benefits associated with this action.
This action does not contain any unfunded mandate as described in UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments. The action imposes no
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 action does not have tribal implications as specified in Executive Order 13175. It would neither impose substantial direct compliance costs on tribal governments, nor preempt Tribal law. Thus, Executive Order 13175 does not apply to this action.
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 is not subject to Executive Order 13045 because it does not concern an environmental health risk or safety risk.
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. This action is not anticipated to have notable impacts on emissions, costs, or energy supply decisions for the affected electric utility industry.
This action does not involve technical standards.
The EPA believes the human health or environmental risk addressed by this action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations because it is limited in scope and only considers cost of whether it is appropriate to regulate HAP emissions from electric utility steam generating units.
Pursuant to CAA section 307(d)(1)(V), the Administrator determines that this action is subject to provisions of section 307(d). Section 307(d) establishes procedural requirements specific to rulemaking under the CAA. Section 307(d)(1)(V) provides that the provisions of section 307(d) apply to “such other actions as the Administrator may determine.”
The statutory authority for this proposed action is provided by sections 112, 301, 302, and 307(d)(1) of the CAA as amended (42 U.S.C. 7412, 7601, 7602, 7607(d)(1)). This action is also subject to section 307(d) of the CAA (42 U.S.C. 7607(d)).
Federal Communications Commission.
Petitions for reconsideration and clarification.
Petitions for Reconsideration and Clarification (Petitions) have been filed in the Commission's rulemaking proceeding by: Rick Kaplan, on behalf of the National Association of Broadcasters (two petitions) and D. Cary Mitchell, on behalf of the Blooston Rural Carriers.
Oppositions to the Petitions must be filed on or before December 16, 2015. Replies to an opposition must be filed on or before December 28, 2015.
Federal Communications Commission, 445 12th Street SW., Washington, DC 20554.
Mark Montano, Wireless Telecommunications Bureau, (202) 418-0691, email:
This is a summary of Commission's document, Report No. 3033, released November 24, 2015. The full text of the Petitions is available for viewing and copying at the FCC Reference Information Center, 445 12th Street SW., Room CY-A257, Washington, DC 20554 or may be accessed online via the Commission's Electronic Comment Filing System at
Research, Education, and Economics, USDA.
Notice of meeting.
In accordance with the Federal Advisory Committee Act, 5 U.S.C. App 2, Section 1408 of the
December 16-18, 2015. The public may file written comments before or up to January 4, 2016.
Beltsville Agricultural Research Center, 10300 Baltimore Avenue, Building 005, Room 020, Beltsville, Maryland 20705. Written comments may be sent to: The National Agricultural Research, Extension, Education, and Economics Advisory Board Office, U.S. Department of Agriculture, Room 332A, Jamie L. Whitten Building, Mail Stop 0321, 1400 Independence Avenue SW., Washington, DC 20250-0321.
Michele Esch, Executive Director or Shirley Morgan-Jordan, Program Support Coordinator, National Agricultural Research, Extension, Education, and Economics Advisory Board; telephone: (202) 720-3684; fax: (202) 720-6199; or email:
On Thursday, December 17, 2015, the full Advisory Board will convene at 8:00 a.m. and adjourn at 5:00 p.m. An evening session will be held at 6:00 p.m. at the Greenbelt Marriott at 6400 Ivy Lane, Greenbelt, Maryland 20770.
On Friday, December 18, 2015, the Board will reconvene at 8:00 a.m. and adjourn at 12:00 p.m. (noon).
Research, Education, and Economics, USDA.
Notice of stakeholder listening session.
In accordance with the Federal Advisory Committee Act, 5 U.S.C. App 2, and the Specialty Crop Competitiveness Act of 2004 (Public Law 108-465), the U. S. Department of Agriculture (USDA) announces a stakeholder listening session of the Specialty Crop Committee, a subcommittee of the National Agricultural Research, Extension, Education, and Economics Advisory Board.
December 10, 2015 starting at 9:00 a.m. EST.
Great Lakes Fruit, Vegetable and Farm Market Expo and Michigan Greenhouse Growers EXPO, DeVos Place Conference Center, River Overlook Room A-B, DeVos Place Convention Center, 303 Monroe Ave. NW., Grand Rapids, Michigan, 49503.
The public may file written comments by December 21, 2015, to: The National Agricultural Research, Extension, Education, and Economics Advisory Board Office, U.S. Department of Agriculture, Room 332-A, Jamie L. Whitten Building, 1400 Independence Avenue SW., Washington, DC, 20250-2255 or
Michele Esch, Executive Director, National Agricultural Research, Extension, Education, and Economics Advisory Board; telephone: (202) 720-8408; fax: (202) 720-6199; or email:
The Specialty Crop Committee was established in accordance with the Specialty Crops Competitiveness Act of 2004 under Title III, Section 303 of Public Law 108-465. This Committee is a permanent subcommittee of the National Agricultural Research Extension, Education, and Economics Advisory Board (the Board). The Committee's charge is to study the scope and effectiveness of research, extension, and economics programs affecting the specialty crop industry. The congressional legislation defines “specialty crops” as fruits, vegetables, tree nuts, dried fruits and nursery crops (including floriculture).
In order to carry out its responsibilities effectively, the Committee is holding a stakeholder listening session. The listening session will elicit stakeholder input from industry and state representatives, national organizations and institutions, local producers, and other groups interested in the issues with which the Specialty Crop Committee is charged. This session will be an opportunity to share ideas on the specialty crop industry with members of USDA's Specialty Crop Committee, including: measures designed to improve the efficiency, productivity, and profitability of specialty crop production in the United States; measures designed to improve competitiveness through research, extension, and economics programs affecting the specialty crop industry; and programs that would: enhance quality and shelf-life, development of new crop protection tools, preventing foreign invasive pests and diseases, developing new and improved marketing tools, and enhancing food safety, improvement of mechanization of production practices, and enhancing irrigation techniques. Input received will help formulate recommendations from the Specialty Crop Committee to USDA.
Written comments by attendees and other interested stakeholders will be welcomed as additional public input by December 21, 2015. All verbal and written statements will become part of the official public record of the REE Advisory Board Office.
Food and Nutrition Service, USDA.
Notice.
In accordance with the Paperwork Reduction Act of 1995, this notice invites the general public and other public agencies to comment on this proposed information collection. This is a revision of an existing collection for the Food and Nutrition Service to describe the roles of community-based organizations (CBOs) in the Supplemental Nutrition Assistance Program (SNAP), and to assess if, and how, the use of CBOs to conduct SNAP applicant interviews has impacted SNAP program outcomes such as timeliness, payment error rates, access, and client satisfaction across five (5) States.
Written comments on this notice must be received on or before February 1, 2016.
Comments are invited on: (a) 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; (b) the accuracy of the agency's burden estimate for the proposed collection of information, including the validity of the methodology and assumptions that were used; (c) ways to minimize the burden of the collection of information on those who are to respond, including use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, and (d) ways to enhance the quality, utility and clarity of the information to be collected.
Comments may be sent to: Rosemarie Downer, Food and Nutrition Service/U.S. Department of Agriculture, 3101 Park Center Drive, Room 1014, Alexandria, VA 22302. Comments may also be submitted via fax to the attention of Rosemarie Downer at 703-305-2576 or via email to
All written comments will be open for public inspection at the office of the Food and Nutrition Service during regular business hours (8:30 a.m. to 5:00 p.m., Monday through Friday) at 3101 Park Center Drive, Room 1014, Alexandria, Virginia 22302.
All responses to this notice will be summarized and included in the request for Office of Management and Budget approval. All comments will also become a matter of public record.
Requests for additional information or copies of this information collection should be directed to Rosemarie Downer at 703-305-2129. Information requests submitted through email should refer to the title of this proposal.
The information collection plan for this follow-up includes a satisfaction survey to be completed by SNAP
Estimated Total Annual Responses: 10.
FNS is requesting 552.48 burden hours.
There is no recordkeeping requirements involved in this data collection.
Forest Service, USDA.
Notice of intent to prepare an environmental impact statement.
In 2007, the Wasatch-Cache National Forest, now the Uinta-Wasatch-Cache National Forest (UWCNF), along with other forests in the Nation issued a number of decisions reissuing term grazing permits on range allotments using a provisional categorical exclusion (CE) authorized by Congress. In 2010, the United States Forest Service was sued for authorizing grazing on allotments using this CE authority. In December 2013, the Intermountain Region and the United States District Court for the District Court of Idaho agreed to the Range CE settlement agreement. This agreement stipulated that the UWCNF would issue a scoping notice by May 2014 on five domestic sheep allotments.
These were Gilbert Peak, Hessie Lake-Henry's Fork, Red Castle, East Fork Blacks Fork, and the Middle Fork Blacks Fork allotments. In reviewing the management of these domestic sheep allotments it became apparent that the effects of grazing had to be considered for both the north and south slope of the Uinta Mountains because sheep trailed from the north slope of the Uinta Mountains to the south slope for the summer grazing season. Therefore, the analysis was then extended to include the Painter Basin, Tungsten, Oweep, Ottoson Basin, and Fall Creek sheep allotments on the Ashley National Forest, which are some of the domestic sheep allotments on the south slope of the Uinta Mountains.
Since 2007, various species of terrestrial and aquatic animals as well as plants have been added to or removed from the Regional Forester's Sensitive Species (RFSS) list. The RFSS will be analyzed as part of the EIS.
In May of 2014, scoping was initiated for this project; at that time, it was anticipated that the project would be completed as an Environmental Assessment. Since then, it has become apparent that there is a potential for significant impacts and that an Environmental Impact Statement is needed. This project will evaluate the effects of continued domestic sheep grazing on these 10 allotments. These 10 sheep allotments located on the north and south slopes of the Uinta Mountains and are located in the Ashley or Uinta-Wasatch-Cache NFs.
Comments concerning the scope of the analysis must be received by December 31, 2015. The draft environmental impact statement is expected around November, 2016 and the final environmental impact statement is expected around October, 2017.
Send written comments to David Whittekiend, Uinta-Wasatch-Cache National Forest Supervisor at 857 West South Jordan Parkway, South Jordan, UT 84095. Comments may also be sent via email to
Paul Cowley, Interdisciplinary Team Leader, at the Uinta-Wasatch Cache Supervisor's Office (telephone: 801-999-2177; email:
Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 between 8 a.m. and 8 p.m., Eastern Time, Monday through Friday.
In response to the requirements of the 2013 settlement, the UWC is required to reassess the effects of domestic sheep grazing on the Gilbert Peak, Hessie Lake-Henry's Fork, Red Castle, East Fork Blacks Fork, and the Middle Fork Blacks Fork allotments. As such there is a need to respond to the requirements of the 2013 settlement. Since the Ashley NF neighbors those allotments to the south (Painter Basin, Tungsten, Oweep, Ottoson Basin, and Fall Creek), and domestic sheep utilize both the north and south slopes of the High Uintas, it was determined that an analysis of all 10 allotments was needed.
With the addition of new species to the RFSS,
The Forest Service will evaluate the 10 sheep allotments on the UWC and Ashley NFs: Those allotments are Gilbert Peak, Hessie Lake-Henry's Fork, Red Castle, East Fork Blacks Fork, and the Middle Fork Blacks Fork on the UWCNF, and Painter Basin, Tungsten, Oweep, Ottoson Basin, and Fall Creek on the Ashley NF.
Based on current information both Forests are proposing to authorize grazing on five allotments on the UWCNF and five allotments on the Ashley NF. Livestock grazing would be authorized using Forest Plan direction to meet or move toward the desired conditions identified in the Forest Plans. The Forests are also proposing to continue to use the sheep driveway that allows for sheep that graze the listed allotments
The project will evaluate multiple resources for impacts to include range, wilderness, recreation, hydrology, wildlife, fisheries and aquatic organisms, plants, soils, as well as potential impacts to economics and society.
The project analysis area is located in Uinta County, Wyoming and Duchesne and Summit Counties, Utah on the Evanston-Mountain View and Duchesne/Roosevelt Ranger Districts. The project area is located approximately 40 miles north-northwest of Duchesne, Utah, and about 40 miles southeast of Evanston, Wyoming. The project area encompasses about 160,000 acres and is located in the Uinta Mountains on both the north and south facing slopes of the central ridgeline.
The Forest Service will begin the environmental analysis in 2015, and the project is anticipated to end in late 2017.
At this time, there are two alternatives that are being considered. The first is the proposed action described above. The second is the “No-Action” alternative which would not authorize grazing on the allotments. During the course of the project analysis, it is possible additional alternatives will be analyzed that may result from public participation or from staff participation, or from both.
There are two Responsible Officials for this project: The Uinta Wasatch Cache Forest Supervisor and the Ashley Forest Supervisor.
The decision to be made includes whether or not sheep grazing will continue on these allotments, and whether or not a site specific Forest Plan amendment could be needed.
Preliminary issues that have been identified include impacts to Rocky Mountain bighorn sheep, wilderness, socioeconomics, recreation, soils, hydrology, and vegetation. Additional issues may arise from the public during the comment process.
Scoping for this project was initiated in May of 2014. At that time a scoping package was sent to interested parties, tribes, and organizations. The proposed action has not changed from that original scoping letter, with the exception that the Forests have decided to prepare an environmental impact statement instead of an environemental assessment.
This notice of intent initiates the scoping process, which guides the development of the environmental impact statement. Following this Notice of Intent, it is anticipated that a second scoping letter describing the nature of the project will be sent to interested parties and organziations in the fall of 2015. There will also be opportunities to comment when the draft EIS is released. Additionally, public meetings are being considered as well, and would occur after a scoping letter was sent out.
The Forest Service is looking for comments identifing issues or concerns with regards to sheep grazing on these allotments. Comments that clearly and concisely articulate a percieved problem, and how to find a solution to that problem are most helpful.
It is important that reviewers provide their comments at such times and in such manner that they are useful to the agency's preparation of the environmental impact statement. Therefore, comments should be provided prior to the close of the comment period and should clearly articulate the reviewer's concerns and contentions.
Comments received in response to this solicitation, including names and addresses of those who comment, will be part of the public record for this proposed action. Comments submitted anonymously will be accepted and considered, however.
Forest Service, USDA.
Notice of intent to prepare an environmental impact statement.
In the North Savery Project, the Medicine Bow-Routt National Forests and Thunder Basin National Grassland, Brush Creek/Hayden Ranger District proposes approximately 6,500 acres of salvage logging, precommercial thinning, and hazard tree clearing on National Forest System lands in the northwest Sierra Madre mountain range. The District also proposes changes to the road system in the project area, including decommissioning 26 miles of roads that are causing direct impacts to watershed resources. The Governor of Wyoming has identified the project area as a priority landscape for treatment under the 2014 Farm Bill and amended Healthy Forests Restoration Act of 2003, which provide for expedited environmental analysis and treatments to address areas affected by insect and disease infestations. Accordingly, the environmental analysis associated with the North Savery Project will proceed according to Section 104 of the Healthy Forests Restoration Act and will be subject to subparts A and C of the U.S. Forest Service Project-Level Predecisional Administrative Review Process documented at 36 CFR 218.
Comments concerning the scope of the analysis must be received by February 1, 2016. The draft environmental impact statement is expected in May 2016 and the final
Send written comments to Medicine Bow National Forest; Attn: Melanie Fullman; PO Box 249, Saratoga, WY 82331. Comments may also be sent via email to
All comments, including names and addresses when provided, are placed in the record and are available for public inspection and copying. The public may inspect comments received at 2171 Highway 130, Saratoga WY. Visitors are encouraged to call ahead to 307-326-2500 to facilitate entry into the building.
Monique Nelson, Medicine Bow National Forest; 2468 Jackson St, Laramie WY 82070; phone (307)745-2310; or email:
Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 between 8 a.m. and 8 p.m., Eastern Time, Monday through Friday.
The purpose of the North Savery Analysis is to (1) promote forest regeneration in stands affected by mountain pine beetle; (2) treat overstocked timber stands to improve growth and vigor; (3) reduce the development of large continuous high hazard fuel conditions in high timber production areas; (4) remove hazard trees from high priority areas affecting public safety; (5) provide merchantable timber products for sale from designated timber units; and (6) relocate, reconstruct, or restore to natural conditions portions of the existing road system that are in need of maintenance or are detrimentally contributing to watershed health.
Over the past decade, a mountain pine beetle epidemic has killed pine trees across thousands of acres of forest land in southern Wyoming. In lodgepole pine forests, approximately 70% of the trees greater than 6″ in diameter are dead or dying from mountain pine beetle infestation. Timber stands in the North Savery Project analysis area are among the most productive growing sites on the Medicine Bow National Forest, and it is a priority to reforest and return these stands to timber production. There is a limited time in which to salvage these trees and recover a sawtimber product. The Governor of Wyoming has identified this project location as a priority area for treatment due to insect and disease infestation.
The Forest Service has identified and will analyze approximately 7,700 acres for salvage harvest. Approximately 2,200 of the analyzed acres will not be harvested in order to conserve watershed heath and wildlife habitat. Acres to be set aside from treatment will be determined based on the analyzed effects to water yields in each watershed and the presence of wildlife and other resources of interest. Overstory Removal and Clearcut treatments would be used in lodgepole pine stands to salvage dead and dying trees; some live trees will also be harvested.
Overstory removal treatments are used in areas that have a significant understory component. The intent is to harvest overstory trees while maintaining understory trees that are too small to be merchantable. Clearcut prescriptions are used in stands that have beetle mortality greater than 70%, are highly mistletoe infested, have low levels of existing regeneration, or where the remaining green trees would be at high risk of windthrow. Species present and the presence, distribution, and health of the understory will dictate what options are available for salvage treatments on a stand-by-stand basis. Generally, lodgepole pine trees over 7.0 inches in diameter would be designated for removal. Trees of all species less than 7.0 inches in diameter would generally remain on site. Areas within units that have large, contiguous components of Engelmann spruce may be retained for wildlife. Subalpine fir, when found as a minor component in lodgepole pine stands, would not be retained unless included as wildlife habitat.
Precommercial thinning is proposed on approximately 1,000 acres of densely regenerating lodgepole pine seedling/sapling stands. Precommercial thinning would improve growth and vigor, reduce stress from overcrowding and competition, and provide for a future stand that is less susceptible to bark beetles.
Some areas identified for salvage harvest include hazard trees along roads, trails, and administrative sites.
The Forest Service proposes to decommission (return to a natural state) approximately 26 miles of roads that are causing direct impacts to wetland and water resources, provide redundant access in areas of high road density, or are in greater sage-grouse core habitat. To ensure adequate access to the area, the Forest Service proposes to add approximately 6 miles of well-placed unauthorized routes to the National Forest road system, convert 1 mile of road to ORV trail, and build approximately 1 mile of ORV trail. Finally, the Forest Service proposes to construct 1 mile of road, reconstruct 2 miles of road, and reroute 1 mile of road. Approximately 20 miles of temporary roads may be needed to facilitate timber harvest.
Melanie B. Fullman, District Ranger; Medicine Bow Routt-National Forests and Thunder Basin National Grassland, Brush Creek/Hayden Ranger District.
The Responsible Official will decide whether to adopt and implement the proposed action, implement an alternative to or modification of the proposed action, or take no action with respect to the North Savery Project.
The following issues were identified while scoping a larger “Savery” project in 2011. The Savery Project was scoped but was not analyzed or implemented. This North Savery Project is located with the former Savery Project analysis area but is smaller in extent and includes fewer proposals. Preliminary issues are: (1) effects of proposed timber salvage treatments on wildlife, wildlife habitat, and watershed funtion; (2) effects of road closures and road decommissioning on recreational access to the national forest.
This notice of intent initiates the scoping process, which guides the development of the environmental impact statement. There will a public meeting held at the Bureau of Land Management Rawlins Field Office located at 1300 North 3rd St., Rawlins WY 82301 on December 9, 2015 from 5:30 p.m. to 7:30 p.m. A second public meeting will be held at the Platte Valley Community Center located at 210 W
It is important that reviewers provide their comments at such times and in such manner that they are useful to the agency's preparation of the environmental impact statement. Therefore, comments should be provided prior to the close of the comment period and should clearly articulate the reviewer's concerns and contentions.
Comments received in response to this solicitation, including names and addresses of those who comment, will be part of the public record for this proposed action. Comments submitted anonymously will be accepted and considered, however.
National Agricultural Statistics Service, USDA.
Notice and request for comments.
In accordance with the Paperwork Reduction Act of 1995, this notice announces the intention the National Agricultural Statistics Service (NASS) to request revision and extension of a currently approved information collection, the Cold Storage Survey. Revision to burden hours will be needed due to changes in the size of the target population, expected increases in response rates, and modes of data collection. The questionnaires have had some minor modifications to accommodate changes in the products stored by the industry, and to make the questionnaires easier to complete. The target population for cold storage operators (both mandatory and voluntary samples) will be contacted for this data on a monthly basis. Fruit storage operations are contacted on a monthly—seasonal basis. The capacity survey is conducted once every other year of all operations with refrigerated storage capacity. Most of these surveys are voluntary; the one exception is for operations that store certain manufactured dairy products that are required by Public Law 106-532 and 107-171 to respond.
Comments on this notice must be received by February 1, 2016 to be assured of consideration.
You may submit comments, identified by docket number 0535-0001, by any of the following methods:
• Email:
• E-fax: (855) 838-6382.
• Mail: Mail any paper, disk, or CD-ROM submissions to: David Hancock, NASS Clearance Officer, U.S. Department of Agriculture, Room 5336 South Building, 1400 Independence Avenue SW., Washington, DC 20250-2024.
• Hand Delivery/Courier: Hand deliver to: David Hancock, NASS Clearance Officer, U.S. Department of Agriculture, Room 5336 South Building, 1400 Independence Avenue SW., Washington, DC 20250-2024.
R. Renee Picanso, Associate Administrator, National Agricultural Statistics Service, U.S. Department of Agriculture, (202) 720-2707. Copies of this information collection and related instructions can be obtained without charge from David Hancock, NASS—OMB Clearance Officer, at (202) 690-2388 or at
NASS also complies with OMB Implementation Guidance, “Implementation Guidance for Title V of the E-Government Act, Confidential Information Protection and Statistical Efficiency Act of 2002 (CIPSEA),”
Most of these surveys are voluntary; the one exception is for operations that store certain manufactured dairy products that are required by Public Law 106-532 and 107-171 to respond.
Copies of this information collection and related instructions can be obtained without charge from David Hancock, NASS Clearance Officer, at (202) 690-2388.
All responses to this notice will become a matter of public record and be summarized in the request for OMB approval.
National Agricultural Statistics Service, USDA.
Notice and request for comments.
In accordance with the Paperwork Reduction Act of 1995, this notice announces the intention the National Agricultural Statistics Service (NASS) to request revision and extension of a currently approved information collection, the Agricultural Prices Surveys. Revision to burden hours will be needed due to changes in the size of the target population, sampling design, and/or questionnaire length.
Comments on this notice must be received by February 1, 2016 to be assured of consideration.
You may submit comments, identified by docket number 0535-0003, by any of the following methods:
• Email:
• E-fax: (855) 838-6382.
• Mail: Mail any paper, disk, or CD-ROM submissions to: David Hancock, NASS Clearance Officer, U.S. Department of Agriculture, Room 5336 South Building, 1400 Independence Avenue SW., Washington, DC 20250-2024.
• Hand Delivery/Courier: Hand deliver to: David Hancock, NASS Clearance Officer, U.S. Department of Agriculture, Room 5336 South Building, 1400 Independence Avenue SW., Washington, DC 20250-2024.
R. Renee Picanso, Associate Administrator, National Agricultural Statistics Service, U.S. Department of Agriculture, (202) 720-2707. Copies of this information collection and related instructions can be obtained without charge from David Hancock, NASS-OMB Clearance Officer, at (202) 690-2388 or at
The Agricultural Prices surveys provide data on the prices received by farmers and prices paid by them for production goods and services. NASS estimates based on these surveys are used as a Principle Economic Indicator of the United States. These price estimates are also used to compute Parity Prices in accordance with requirements of the Agricultural Adjustment Act of 1938 as amended (Title III, Subtitle A, Section 301(a)). In addition, price data are used by the Federal Crop Insurance Corporation to help determine payment rates, program option levels, and disaster programs.
These data will be collected under authority of 7 U.S.C. 2204(a). Individually identifiable data collected under this authority are governed by Section 1770 of the Food Security Act of 1985 as amended, 7 U.S.C. 2276, which requires USDA to afford strict confidentiality to non-aggregated data provided by respondents. This Notice is submitted in accordance with the Paperwork Reduction Act of 1995 (Pub. L. 104-113) and Office of Management and Budget regulations at 5 CFR part 1320.
NASS also complies with OMB Implementation Guidance, “Implementation Guidance for Title V of the E-Government Act, Confidential Information Protection and Statistical Efficiency Act of 2002 (CIPSEA),”
Copies of this information collection and related instructions can be obtained without charge from David Hancock, NASS Clearance Officer, at (202) 690-2388.
Comments: Comments are invited on: (a) 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; (b) 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; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on those who are to respond, through the use of appropriate automated, electronic, mechanical, technological or other forms of information technology collection methods.
All responses to this notice will become a matter of public record and will be summarized in the request for OMB approval.
National Agricultural Statistics Service, USDA.
Notice and request for comments.
In accordance with the Paperwork Reduction Act of 1995, this notice announces the intention of the National Agricultural Statistics Service (NASS) to request extension without change of a currently approved information collection, the Generic Clearance for Survey Research Studies. There are no revisions to burden hours or the number of responses under this information collection request.
Comments on this notice must be received by February 1, 2016 to be assured of consideration.
You may submit comments, identified by docket number 0535-0248, by any of the following methods:
• Email:
• E-fax: (855) 838-6382.
• Mail: Mail any paper, disk, or CD-ROM submissions to: David Hancock, NASS Clearance Officer, U.S. Department of Agriculture, Room 5336
• Hand Delivery/Courier: Hand deliver to: David Hancock, NASS Clearance Officer, U.S. Department of Agriculture, Room 5336 South Building, 1400 Independence Avenue SW., Washington, DC 20250-2024.
R. Renee Picanso, Associate Administrator, National Agricultural Statistics Service, U.S. Department of Agriculture, (202) 720-2707. Copies of this information collection and related instructions can be obtained without charge from David Hancock, NASS—OMB Clearance Officer, at (202) 690-2388 or at
In the last decade, state-of-the art techniques have been increasingly instituted by NASS and other Federal agencies and are now routinely used to improve the quality and timeliness of survey data and analyses, while simultaneously reducing respondents' cognitive workload and burden. The purpose of this generic clearance is to allow NASS to continue to adopt and use these state-of-the-art techniques to improve its current data collections efforts. These tests will also be used to aid in the development of new surveys.
NASS envisions using a variety of survey improvement techniques, as appropriate to the individual project under investigation. These include focus groups, cognitive and usability laboratory and field techniques, exploratory interviews, behavior coding, respondent debriefing, pilot surveys, and split-panel tests. After obtaining participants' permission, NASS plans to audio-record some cognitive interviews and usability interviews, in order to allow for more complete and accurate summaries of these qualitative interviews. This is a standard procedure for cognitive interviews and usability interviews at many other survey organizations, including Federal agencies. The consent form would be used for audio recording some cognitive interviews and usability interviews for research purposes. For these types of interviews, there will be no collection of Personally Identifiable Information (PII) or any identifying information about the operator or operation.
Following standard OMB requirements NASS will submit a change request to OMB individually for each survey improvement project it undertakes under this generic clearance and provide OMB with a copy of the questionnaire (if one is used), and all other materials describing the project.
NASS also complies with OMB Implementation Guidance, “Implementation Guidance for Title V of the E-Government Act, Confidential Information Protection and Statistical Efficiency Act of 2002 (CIPSEA),”
All responses to this notice will become a matter of public record and be summarized in the request for OMB approval.
Pursuant to its authority under the Foreign-Trade Zones Act of June 18, 1934, as amended (19 U.S.C. 81a-81u), the Foreign-Trade Zones Board (the Board) adopts the following Order:
Pursuant to its authority under the Foreign-Trade Zones Act of June 18, 1934, as amended (19 U.S.C. 81a-81u), the Foreign-Trade Zones Board (the Board) adopts the following Order:
Pursuant to its authority under the Foreign-Trade Zones Act of June 18, 1934, as amended (19 U.S.C. 81a-81u), the Foreign-Trade Zones Board (the Board) adopts the following Order:
Pursuant to its authority under the Foreign-Trade Zones Act of June 18, 1934, as amended (19 U.S.C. 81a-81u), the Foreign-Trade Zones Board (the Board) adopts the following Order:
The application to reorganize FTZ 258 under the ASF is approved, subject to
Pursuant to its authority under the Foreign-Trade Zones Act of June 18, 1934, as amended (19 U.S.C. 81a-81u), the Foreign-Trade Zones Board (the Board) adopts the following Order:
The application to reorganize FTZ 33 under the ASF is approved, subject to the FTZ Act and the Board's regulations, including Section 400.13, to the Board's standard 2,000-acre activation limit for the zone, to an ASF sunset provision for magnet sites that would terminate authority for Sites 2 and 18 if not activated within five years from the month of approval, and to an ASF sunset provision for usage-driven sites that would terminate authority for Sites 3, 4, 5 and 10 if no foreign-status merchandise is admitted for a
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (the Department) is conducting an administrative review of the antidumping duty order on polyethylene terephthalate film, sheet, and strip (PET Film) from the United Arab Emirates (UAE). The period of review (POR) is November 1, 2013, through October 31, 2014. The review covers one producer/exporter of the subject merchandise, JBF RAK LLC (JBF). The Department preliminarily determines that sales of subject merchandise have been made below normal value by JBF. Interested parties are invited to comment on these preliminary results.
Andrew Huston, AD/CVD Operations, Office VII, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-4261.
The products covered by the order are all gauges of raw, pre-treated, or primed polyethylene terephthalate film, whether extruded or co-extruded. Excluded are metallized films and other finished films that have had at least one of their surfaces modified by the application of a performance-enhancing resinous or inorganic layer more than 0.00001 inches thick. Also excluded is roller transport cleaning film which has at least one of its surfaces modified by application of 0.5 micrometers of SBR latex. Tracing and drafting film is also excluded. Polyethylene terephthalate film is classifiable under subheading 3920.62.00.90 of the Harmonized Tariff Schedule of the United States (HTSUS). While HTSUS subheadings are provided for convenience and customs purposes, our written description of the scope of the order is dispositive.
The Department is conducting this review in accordance with section 751(a) of the Tariff Act of 1930, as amended (the Act). Export price is calculated in accordance with section 772 of the Act. Normal value is calculated in accordance with section 773 of the Act.
For a full description of the methodology underlying our conclusions,
As a result of our review, we preliminarily determine the following weighted-average dumping margins exist for the period November 1, 2013, through October 31, 2014:
The Department intends to disclose the calculations used in our analysis to parties in this review within five days of the date of publication of this notice in accordance with 19 CFR 351.224(b). Interested parties are invited to comment on the preliminary results of this review. Pursuant to 19 CFR 351.309(c)(1)(ii), interested parties may submit case briefs not later than 30 days after the date of publication of this notice. Rebuttal briefs, limited to issues raised in the case briefs, may not be filed later than five days after the time limit for filing case briefs.
Pursuant to 19 CFR 351.310(c), any interested party may request a hearing within 30 days of the publication of this notice in the
We intend to issue the final results of this administrative review, including the results of our analysis of issues raised by the parties in the written comments, within 120 days of publication of these preliminary results in the
Upon issuing the final results of the review, the Department shall determine, and U.S. Customs and Border Protection (CBP) shall assess, antidumping duties on all appropriate entries. The Department intends to issue assessment instructions to CBP 15 days after the date of publication of the final results of review.
For any individually examined respondents whose weighted-average dumping margin is above
The final results of this review shall be the basis for the assessment of antidumping duties on entries of merchandise covered by the final results of this review and for future deposits of estimated duties, where applicable.
The following deposit requirements will be effective for all shipments of PET Film from the UAE entered, or withdrawn from warehouse, for consumption on or after the date of publication of the final results of this administrative review, as provided for by section 751(a)(2)(C) of the Act: (1) the cash deposit rate for the companies under review will be the rate established in the final results of this review (except, if the rate is zero or
This notice also serves as a preliminary reminder to importers of their responsibility under 19 CFR 351.402(f) to file a certificate regarding the reimbursement of antidumping duties prior to liquidation of the relevant entries during this review period. Failure to comply with this requirement could result in the Department's presumption that reimbursement of antidumping duties occurred and the subsequent assessment of double antidumping duties.
These preliminary results of administrative review are issued and published in accordance with sections 751(a)(1) and 777(i)(1) of the Act.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
Based on affirmative final determinations by the Department of Commerce (the Department) and the International Trade Commission (ITC), the Department is issuing a countervailing duty order on welded line pipe from the Republic of Turkey (Turkey).
Elizabeth Eastwood, AD/CVD Operations, Office II, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-3874.
On October 13, 2015, the Department published its final determination in the countervailing duty investigation of welded line pipe from Turkey.
The merchandise covered by this order is circular welded carbon and alloy steel (other than stainless steel) pipe of a kind used for oil or gas pipelines (welded line pipe), not more than 24 inches in nominal outside diameter, regardless of wall thickness, length, surface finish, end finish, or stenciling. Welded line pipe is normally produced to the American Petroleum Institute (API) specification 5L, but can be produced to comparable foreign specifications, to proprietary grades, or can be non-graded material. All pipe meeting the physical description set forth above, including multiple-stenciled pipe with an API or comparable foreign specification line pipe stencil is covered by the scope of this order.
The welded line pipe that is subject to this order is currently classifiable in the Harmonized Tariff Schedule of the United States (HTSUS) under subheadings 7305.11.1030, 7305.11.5000, 7305.12.1030, 7305.12.5000, 7305.19.1030, 7305.19.5000, 7306.19.1010, 7306.19.1050, 7306.19.5110, and 7306.19.5150. The subject merchandise may also enter in HTSUS 7305.11.1060 and 7305.12.1060. While the HTSUS subheadings are provided for convenience and customs purposes, the written description of the scope of this order is dispositive.
In accordance with sections 705(b)(1)(A)(i) and 705(d) of the Act, the ITC has notified the Department of its final determination that the industry in the United States producing welded line pipe is materially injured by reason of subsidized imports of welded line pipe from Turkey. Therefore, in accordance with section 705(c)(2) of the Act, we are publishing this countervailing duty order.
As a result of the ITC's final determination, in accordance with section 706(a) of the Act, the Department will direct U.S. Customs and Border Protection (CBP) to assess, upon further instruction by the Department, countervailing duties on unliquidated entries of welded line pipe entered, or withdrawn from warehouse, for consumption on or after March 20, 2015, the date on which the Department published its preliminary countervailing duty determination in the
In accordance with section 706 of the Act, the Department will direct CBP to reinstitute the suspension of liquidation of welded line pipe from Turkey, effective the date of publication of the ITC's notice of final determination in the
This notice constitutes the countervailing duty order with respect to welded line pipe from Turkey, pursuant to section 706(a) of the Act. Interested parties may contact the Department's Central Records Unit, Room B8024 of the main Commerce Building, for a copy of an updated list of countervailing duty orders currently in effect.
This order is issued and published in accordance with section 706(a) of the Act and 19 CFR 351.211(b).
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (the Department) is conducting an administrative review of the antidumping duty order on brass sheet and strip from France,
Mark Flessner or Robert James, AD/CVD Operations, Office VI, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-6312 or (202) 482-0649, respectively.
The product covered by the orders is brass sheet and strip, other than leaded and tinned brass sheet and strip, from France. The merchandise is currently classified under Harmonized Tariff Schedule of the United States (HTSUS) item numbers 7409.21.00 and 7409.29.00.
A full description of the scope of the order is contained in the Preliminary Decision Memorandum.
Because both Griset and KME France failed to respond to the Department's questionnaire, we preliminarily determined to rely on facts available with an adverse inference with respect to Griset and KME France, in accordance with sections 776(a) and (b) of the Act and 19 CFR 351.308. Thus, we preliminarily assigned a rate of 42.24 percent as the weighted-average dumping margin for both Griset and KME France.
As a result of this review, we preliminarily determine that the following weighted-average dumping margins on brass sheet and strip from France exist for the period March 1, 2014, through February 28, 2015, at the following rates:
Pursuant to 19 CFR 351.309(c), interested parties may submit case briefs not later than 30 days after the date of publication of this notice. Rebuttal briefs, limited to issues raised in the case briefs, may be filed not later than five days after the date for filing case briefs.
When submitting a document to the Department
The Department intends to issue the final results of this administrative review, including the results of its analysis of the issues raised in any written briefs, not later than 120 days after the date of publication of this notice, unless extended, pursuant to section 751(a)(3)(A) of the Act.
Upon completion of the administrative review, the Department shall determine, and U.S. Customs and Border Protection (CBP) shall assess, antidumping duties on all appropriate entries covered by this review. For the final results, if we continue to rely on adverse facts available to establish the weighted-average dumping margins for Griset and KME France, we will instruct U.S. Customs and Border Protection (CBP) to apply an
The Department clarified its “automatic assessment” regulation on May 6, 2003.
We intend to issue liquidation instructions to CBP 15 days after publication of the final results of review.
The following deposit requirements will be effective upon publication of the notice of final results of administrative review for all shipments of brass sheet and strip from France entered, or withdrawn from warehouse, for consumption on or after the date of publication as provided by section 751(a)(2) of the Act: (1) The cash deposit rate for Griset and KME France will be equal to the weighted-average dumping margin established in the final results of this administrative review except if the rate is
This notice serves as a preliminary reminder to importers of their responsibility under 19 CFR 351.402(f)(2) to file a certificate regarding the reimbursement of antidumping duties prior to liquidation of the relevant entries during this review period. Failure to comply with this requirement could result in the Secretary's presumption that reimbursement of antidumping duties occurred and the subsequent assessment of doubled antidumping duties.
We are issuing and publishing these results in accordance with sections 751(a)(1) and 777(i)(1) of the Act.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
Based on affirmative final determinations by the Department of Commerce (the Department) and the International Trade Commission (the ITC), the Department is issuing antidumping duty orders on welded line pipe from the Republic of Korea (Korea) and the Republic of Turkey (Turkey).
Ross Belliveau (Korea) or David Crespo (Turkey), AD/CVD Operations, Office II, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 1401 Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-4952 and (202) 482-3693, respectively.
In accordance with sections 735(d) and 777(i)(1) of the Tariff Act of 1930, as amended (the Act), and 19 CFR 351.210(c), on October 13, 2015, the Department published its affirmative final determinations in the less-than-fair-value (LTFV) investigations of welded line pipe from Korea and Turkey.
The merchandise covered by these orders is circular welded carbon and alloy steel (other than stainless steel) pipe of a kind used for oil or gas pipelines (welded line pipe), not more than 24 inches in nominal outside diameter, regardless of wall thickness, length, surface finish, end finish, or stenciling. Welded line pipe is normally produced to the American Petroleum Institute (API) specification 5L, but can be produced to comparable foreign specifications, to proprietary grades, or can be non-graded material. All pipe meeting the physical description set forth above, including multiple-stenciled pipe with an API or comparable foreign specification line pipe stencil is covered by the scope of these orders.
The welded line pipe that is subject to these orders is currently classifiable in the Harmonized Tariff Schedule of the United States (HTSUS) under subheadings 7305.11.1030, 7305.11.5000, 7305.12.1030, 7305.12.5000, 7305.19.1030, 7305.19.5000, 7306.19.1010, 7306.19.1050, 7306.19.5110, and 7306.19.5150. The subject merchandise may also enter in HTSUS 7305.11.1060 and 7305.12.1060. While the HTSUS subheadings are provided for
As stated above, on November 20, 2015, in accordance with section 735(d) of the Act, the ITC notified the Department of its final determinations in these investigations, in which it found material injury with respect to welded line pipe from Korea and Turkey.
Therefore, in accordance with section 736(a)(1) of the Act, the Department will direct U.S. Customs and Border Protection (CBP) to assess, upon further instruction by the Department, antidumping duties equal to the amount by which the normal value of the merchandise exceeds the export price (or constructed export price) of the merchandise, for all relevant entries of welded line pipe from Korea and Turkey. Antidumping duties will be assessed on unliquidated entries of welded line pipe from Korea and Turkey entered, or withdrawn from warehouse, for consumption on or after May 22, 2015, the date of publication of the preliminary determinations,
In accordance with section 735(c)(1)(B) of the Act, we will instruct CBP to continue to suspend liquidation on all relevant entries of welded line pipe from Korea and Turkey. These instructions suspending liquidation will remain in effect until further notice.
We will also instruct CBP to require cash deposits equal to the amounts as indicated below. Accordingly, effective on the date of publication of the ITC's final affirmative injury determinations, CBP will require, at the same time as importers would normally deposit estimated duties on this subject merchandise, a cash deposit equal to the estimated weighted-average dumping margins listed below.
Section 733(d) of the Act states that instructions issued pursuant to an affirmative preliminary determination may not remain in effect for more than four months, except where exporters representing a significant proportion of exports of the subject merchandise request the Department to extend that four-month period to no more than six months. At the request of exporters that account for a significant proportion of welded line pipe from Korea and Turkey, we extended the four-month period to six months in each case.
Therefore, in accordance with section 733(d) of the Act and our practice, we will instruct CBP to terminate the suspension of liquidation and to liquidate, without regard to antidumping duties, unliquidated entries of welded line pipe from Korea and Turkey entered, or withdrawn from warehouse, for consumption after November 18, 2015, the date on which the provisional measures expired, until and through the day preceding the date of publication of the ITC's final injury determinations in the
The weighted-average dumping margins are as follows:
This notice constitutes the antidumping duty orders with respect to welded line pipe from Korea and Turkey pursuant to section 736(a) of the Act. Interested parties can find a list of antidumping duty orders currently in effect at
These orders are published in accordance with section 736(a) of the Act and 19 CFR 351.211.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
Brenda E. Waters, Office of AD/CVD Operations, Customs Liaison Unit, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230, telephone: (202) 482-4735.
Each year during the anniversary month of the publication of an antidumping or countervailing duty order, finding, or suspended investigation, an interested party, as defined in section 771(9) of the Tariff Act of 1930, as amended (“the Act”), may request, in accordance with 19 CFR 351.213, that the Department of Commerce (“the Department”) conduct an administrative review of that antidumping or countervailing duty order, finding, or suspended investigation.
All deadlines for the submission of comments or actions by the Department discussed below refer to the number of calendar days from the applicable starting date.
In the event the Department limits the number of respondents for individual examination for administrative reviews initiated pursuant to requests made for the orders identified below, the Department intends to select respondents based on U.S. Customs and Border Protection (“CBP”) data for U.S. imports during the period of review. We intend to release the CBP data under Administrative Protective Order (“APO”) to all parties having an APO within five days of publication of the initiation notice and to make our decision regarding respondent selection within 21 days of publication of the initiation
In the event the Department decides it is necessary to limit individual examination of respondents and conduct respondent selection under section 777A(c)(2) of the Act:
In general, the Department finds that determinations concerning whether particular companies should be “collapsed” (
Pursuant to 19 CFR 351.213(d)(1), a party that requests a review may withdraw that request within 90 days of the date of publication of the notice of initiation of the requested review. The regulation provides that the Department may extend this time if it is reasonable to do so. In order to provide parties additional certainty with respect to when the Department will exercise its discretion to extend this 90-day deadline, interested parties are advised that, with regard to reviews requested on the basis of anniversary months on or after December 2015, the Department does not intend to extend the 90-day deadline unless the requestor demonstrates that an extraordinary circumstance prevented it from submitting a timely withdrawal request. Determinations by the Department to extend the 90-day deadline will be made on a case-by-case basis.
The Department is providing this notice on its Web site, as well as in its “Opportunity to Request Administrative Review” notices, so that interested parties will be aware of the manner in which the Department intends to exercise its discretion in the future.
Opportunity to Request a Review: Not later than the last day of December 2015,
In accordance with 19 CFR 351.213(b), an interested party as defined by section 771(9) of the Act may request in writing that the Secretary conduct an administrative review. For both antidumping and countervailing duty reviews, the interested party must specify the individual producers or exporters covered by an antidumping finding or an antidumping or countervailing duty order or suspension agreement for which it is requesting a review. In addition, a domestic interested party or an interested party described in section 771(9)(B) of the Act must state why it desires the Secretary to review those particular producers or exporters. If the interested party intends for the Secretary to review sales of merchandise by an exporter (or a producer if that producer also exports merchandise from other suppliers) which was produced in more than one country of origin and each country of origin is subject to a separate order, then the interested party must state specifically, on an order-by-order basis, which exporter(s) the request is intended to cover.
Note that, for any party the Department was unable to locate in prior segments, the Department will not accept a request for an administrative
As explained in
Further, as explained in
Following initiation of an antidumping administrative review when there is no review requested of the NME entity, the Department will instruct CBP to liquidate entries for all exporters not named in the initiation notice, including those that were suspended at the NME entity rate.
All requests must be filed electronically in Enforcement and Compliance's Antidumping and Countervailing Duty Centralized Electronic Service System (“ACCESS”) on Enforcement and Compliance's ACCESS Web site at
The Department will publish in the
For the first administrative review of any order, there will be no assessment of antidumping or countervailing duties on entries of subject merchandise entered, or withdrawn from warehouse, for consumption during the relevant provisional-measures “gap” period of the order, if such a gap period is applicable to the period of review.
This notice is not required by statute but is published as a service to the international trading community.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (the Department) is conducting an administrative review of the antidumping duty order on aluminum extrusions from the People's Republic of China (PRC).
The Department finds for these final results that Union made sales of subject merchandise at less than normal value. In addition, the Department determines that Jangho, Guang Ya Group/Zhongya/Xinya, and 15 other companies subject to this review did not demonstrate eligibility for a separate rate, and, accordingly, are to be considered part of the PRC-wide entity. We also determine for these final results that one company, Xin Wei Aluminum Company Limited (Xin Wei), had no shipments.
Deborah Scott, Mark Flessner, or Robert James, AD/CVD Operations, Office VI, Enforcement and Compliance, International Trade Administration, Department of Commerce, 1401 Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-2657, (202) 482-6312 or (202) 482-0649, respectively.
On June 8, 2015, the Department published the
The merchandise covered by the
Imports of the subject merchandise are provided for under the following categories of the Harmonized Tariff Schedule of the United States (HTSUS): 7609.00.00, 7610.10.00, 7610.90.00, 7615.10.30, 7615.10.71, 7615.10.91, 7615.19.10, 7615.19.30, 7615.19.50, 7615.19.70, 7615.19.90, 7615.20.00, 7616.99.10, 7616.99.50, 8479.89.98, 8479.90.94, 8513.90.20, 9403.10.00, 9403.20.00, 7604.21.00.00, 7604.29.10.00, 7604.29.30.10, 7604.29.30.50, 7604.29.50.30, 7604.29.50.60, 7608.20.00.30, 7608.20.00.90, 8302.10.30.00, 8302.10.60.30, 8302.10.60.60, 8302.10.60.90, 8302.20.00.00, 8302.30.30.10, 8302.30.30.60, 8302.41.30.00, 8302.41.60.15, 8302.41.60.45, 8302.41.60.50, 8302.41.60.80, 8302.42.30.1 0, 8302.42.30.15, 8302.42.30.65, 8302.49.60.35, 8302.49.60.45, 8302.49.60.55, 8302.49.60.85, 8302.50.00.00, 8302.60.90.00, 8305.10.00.50, 8306.30.00.00, 8414.59.60.90, 8415.90.80.45, 8418.99.80.05, 8418.99.80.50, 8418.99.80.60, 8419.90.10.00, 8422.90.06.40, 8473.30.20.00, 8473.30.51.00, 8479.90.85.00, 8486.90.00.00, 8487.90.00.80, 8503.00.95.20, 8508.70.00.00, 8515.90.20.00, 8516.90.50.00, 8516.90.80.50, 8517.70.00.00, 8529.90.73.00, 8529.90.97.60, 8536.90.80.85, 8538.10.00.00, 8543.90.88.80, 8708.29.50.60, 8708.80.65.90, 8803.30.00.60, 9013.90.50.00, 9013.90.90.00, 9401.90.50.81, 9403.90.10.40, 9403.90.10.50, 9403.90.10.85, 9403.90.25.40, 9403.90.25.80, 9403.90.40.05, 9403.90.40.10, 9403.90.40.60, 9403.90.50.05, 9403.90.50.10, 9403.90.50.80, 9403.90.60.05, 9403.90.60.10, 9403.90.60.80, 9403.90.70.05, 9403.90.70.10, 9403.90.70.80, 9403.90.80.10, 9403.90.80.15, 9403.90.80.20, 9403.90.80.41, 9403.90.80.51, 9403.90.80.61, 9506.11.40.80, 9506.51.40.00, 9506.51.60.00, 9506.59.40.40, 9506.70.20.90, 9506.91.00.10, 9506.91.00.20, 9506.91.00.30, 9506.99.05.10, 9506.99.05.20, 9506.99.05.30, 9506.99.15.00, 9506.99.20.00, 9506.99.25.80, 9506.99.28.00, 9506.99.55.00, 9506.99.60.80, 9507.30.20.00, 9507.30.40.00, 9507.30.60.00, 9507.90.60.00, and 9603.90.80.50.
The subject merchandise entered as parts of other aluminum products may be classifiable under the following additional chapter 76 subheadings: 7610.10, 7610.90, 7615.19, 7615.20, and 7616.99 as well as under other HTSUS chapters. In addition, fin evaporator coils may be classifiable under HTSUS numbers: 8418.99.80.50 and 8418.99.80.60. While HTSUS subheadings are provided for convenience and customs purposes, the written description of the scope of this
All issues raised in the case and rebuttal briefs filed by parties in this review are addressed in the Issues and Decision Memorandum, which is incorporated herein by reference. A list of the issues which parties raised, and to which we respond in the Issues and Decision Memorandum, follows as an appendix to this notice. The Issues and Decision Memorandum is a public document and is on file electronically
Based on an analysis of the comments received from interested parties and a review of the record, the Department corrected calculation errors for the final adjusted margin to be applied to Union. For a full explanation, see the Issues and Decision Memorandum at Comment 2. This recalculation of Union's rate affected the rate for other companies;
In our
Neither the Tariff Act of 1930, as amended (the Act), nor the Department's regulations address the establishment of the rate applied to individual separate rate companies not selected for examination where the Department limited its examination in an administrative review pursuant to section 777A(c)(2) of the Act. The Department's practice in administrative reviews involving limited selection based on exporters accounting for the largest volumes of trade has been to look to section 735(c)(5) of the Act for guidance, which provides instructions for calculating the all-others rate in a market-economy antidumping investigation. Section 735(c)(5)(A) of the Act instructs the Department to avoid calculating an all-others rate using any rates that are zero,
In the
One company remaining under review, Xin Wei, timely submitted a certification indicating that it had no sales, shipments, or entries of subject merchandise during the POR.
In the
In addition, 14 companies still subject to these final results are not eligible for separate-rate status because they did not submit separate-rate applications or certifications; those companies are: Aluminicaste Fundicion de Mexico; China Zhongwang Holdings, Ltd.; Classic & Contemporary Inc.; Dongguan Golden Tiger; Dongguan Golden Tiger Hardware Industrial Co., Ltd.; Gold Mountain International Development, Ltd.; Golden Dragon Precise Copper Tube Group, Inc.; Metaltek Metal Industry Co., Ltd.; Nidec Sankyo Singapore Pte. Ltd.; Press Metal International Ltd.; tenKsolar, Inc.; Tianjin Jinmao Import & Export Corp., Ltd.; WTI Building Products, Ltd.; and Zahoqing China Square Industry Limited/Zhaoqing China Square Industry Limited.
Because no mandatory respondent established eligibility for an adjustment under section 777A(f) of the Act for countervailable domestic subsidies, the Department, for these final results, did not make an adjustment pursuant to section 777A(f) of the Act for countervailable domestic subsidies for Union or the separate-rate recipients.
Pursuant to section 772(c)(1)(C) of the Act, the Department made an adjustment for countervailable export subsidies. For Union, we made adjustments to its reported U.S. price.
For the PRC-wide entity, since the entity is not currently under review, no adjustments were warranted to its rate, as its rate is not subject to change.
The Department determines that the following weighted-average dumping margins exist for the POR for these final results:
Additionally, the Department determines for these final results that the following companies are part of the PRC-wide entity: Jangho (which includes Guangzhou Jangho Curtain Wall System Engineering Co., Ltd. and Jangho Curtain Wall Hong Kong Ltd.); Guang Ya Group/Zhongya/Xinya (which includes Guang Ya Aluminium Industries Co., Ltd.; Foshan Guangcheng Aluminium Co., Ltd.; Kong Ah International Company Limited; Guang Ya Aluminium Industries (Hong Kong) Ltd.; Guangdong Zhongya Aluminium Company Limited; Zhongya Shaped Aluminium (HK) Holding Limited; Karlton Aluminum Company Ltd.; and Xinya Aluminum & Stainless Steel Product Co., Ltd.); Aluminicaste Fundicion de Mexico; China Zhongwang Holdings, Ltd.; Classic & Contemporary Inc.; Dongguan Golden Tiger; Dongguan Golden Tiger Hardware Industrial Co., Ltd.; Gold Mountain International Development, Ltd.; Golden Dragon Precise Copper Tube Group, Inc.; Metaltek Metal Industry Co., Ltd.; Nidec Sankyo Singapore Pte. Ltd.; Press Metal International Ltd.; Shenyang Yuanda Aluminium Industry Engineering Co., Ltd.; tenKsolar, Inc.; Tianjin Jinmao Import & Export Corp., Ltd.; WTI Building Products, Ltd.; and Zahoqing China Square Industry Limited/Zhaoqing China Square
Pursuant to section 751(a)(2)(A) of the Act and 19 CFR 351.212(b), the Department will determine, and U.S. Customs and Border Protection (CBP) shall assess, antidumping duties on all appropriate entries. The Department intends to issue assessment instructions to CBP 15 days after the date of publication of the final results of review in the
For each individually-examined respondent whose weighted-average dumping margin is above
The following cash deposit requirements will be effective upon publication of the final results of this administrative review for all shipments of the subject merchandise from the PRC entered, or withdrawn from warehouse, for consumption on or after the publication date, as provided for by section 751(a)(2)(C) of the Act: (1) for Union and the other companies eligible for a separate rate, the cash deposit rate will that listed above in the section “Final Results of Review”; (2) for previously investigated or reviewed PRC and non-PRC exporters not listed above that have a separate rate, the cash deposit rate will continue to be the exporter-specific rate published for the most recently completed segment of this proceeding in which the exporter was reviewed; (3) for all PRC exporters of subject merchandise which have not been found to be entitled to a separate rate, the cash deposit rate will be that established for the PRC-wide entity of 33.28 percent;
The Department intends to disclose to the parties the calculations performed for these final results within five days of the date of publication of this notice in accordance with 19 CFR 351.224(b).
This notice serves as a final reminder to importers of their responsibility under 19 CFR 351.402(f)(2) to file a certificate regarding the reimbursement of antidumping duties and/or countervailing duties prior to liquidation of the relevant entries during this POR. Failure to comply with this requirement could result in the Department's presumption that reimbursement of antidumping duties and/or countervailing duties occurred and the subsequent assessment of doubled antidumping duties.
This notice serves as the only reminder to parties subject to administrative protective order (APO) of their responsibility concerning the disposition of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3), which continues to govern business proprietary information in this segment of the proceeding. 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 the terms of an APO is a sanctionable violation.
This administrative review and notice are issued and published in accordance with sections 751(a)(1) and 777(i)(1) of the Act and 19 CFR 351.213(h).
Enforcement and Compliance, International Trade Administration, Department of Commerce.
In accordance with section 751(c) of the Tariff Act of 1930, as amended (“the Act”), the Department of Commerce (“the Department”) is automatically initiating the five-year review (“Sunset Review”) of the antidumping and countervailing duty (“AD/CVD”) orders listed below. The International Trade Commission (“the Commission”) is publishing concurrently with this notice its notice of
The Department official identified in the
The Department's procedures for the conduct of Sunset Reviews are set forth in its
In accordance with 19 CFR 351.218(c), we are initiating Sunset Reviews of the following antidumping and countervailing duty orders:
As a courtesy, we are making information related to sunset proceedings, including copies of the pertinent statute and Department's regulations, the Department's schedule for Sunset Reviews, a listing of past revocations and continuations, and current service lists, available to the public on the Department's Web site at the following address:
This notice serves as a reminder that any party submitting factual information in an AD/CVD proceeding must certify to the accuracy and completeness of that information.
On April 10, 2013, the Department modified two regulations related to AD/CVD proceedings: The definition of factual information (19 CFR 351.102(b)(21)), and the time limits for the submission of factual information (19 CFR 351.301).
Pursuant to 19 CFR 351.103(d), the Department will maintain and make available a public service list for these proceedings. Parties wishing to participate in any of these five-year reviews must file letters of appearance as discussed at 19 CFR 351.103(d)). To facilitate the timely preparation of the public service list, it is requested that those seeking recognition as interested parties to a proceeding submit an entry of appearance within 10 days of the publication of the Notice of Initiation.
Because deadlines in Sunset Reviews can be very short, we urge interested parties who want access to proprietary information under administrative protective order (“APO”) to file an APO application immediately following publication in the
Domestic interested parties, as defined in section 771(9)(C), (D), (E), (F), and (G) of the Act and 19 CFR 351.102(b), wishing to participate in a Sunset Review must respond not later than 15 days after the date of publication in the
If we receive an order-specific notice of intent to participate from a domestic interested party, the Department's
This notice of initiation is being published in accordance with section 751(c) of the Act and 19 CFR 351.218(c).
National Marine Fisheries Service, National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of availability; extension of public comment period.
NOAA's National Marine Fisheries Service (NMFS) announces the extension of the comment period for the notice of availability of the public draft of the Endangered Species Act Coastal Multispecies Recovery Plan for the California Coastal Chinook salmon (
The deadline for receipt of comments on the Public Draft Recovery Plan published on October 5, 2015 (80 FR 60125), is extended to close of business on January 18, 2016.
You may submit comments on the Public Draft Recovery Plan by the following methods:
•
•
Electronic copies of the Public Draft Recovery Plan are available online at:
Korie Schaeffer, (707) 575-6087,
On October 5, 2015, (80 FR 60125) we (NMFS) published in the
The Endangered Species Act of 1973 (ESA), as amended (16 U.S.C. 1531
Our goal is to restore the threatened CC Chinook salmon, and NC and CCC steelhead to the point where they are self-sustaining populations within their ecosystems and no longer need the protections of the ESA.
The ESA requires recovery plans incorporate, to the maximum extent practicable: (1) Objective, measurable criteria which, when met, would result in a determination that the species is no longer threatened or endangered; (2) site-specific management actions necessary to achieve the plan's goal for the conservation and survival of the species; and (3) estimates of the time required and costs to implement recovery actions.
The Public Draft Recovery Plan provides background on the natural history, population trends and the potential threats to the viability of CC Chinook salmon, and NC and CCC steelhead. The Public Draft Recovery Plan lays out a recovery strategy to address conditions and threats based on the best available science and incorporates objective, measurable criteria for recovery. The Public Draft Recovery Plan is not regulatory, but presents guidance for use by agencies and interested parties to assist in the recovery of CC Chinook salmon, and NC and CCC steelhead. The Public Draft
Recovery of CC Chinook salmon, and NC and CCC steelhead will require a long-term effort in cooperation and coordination with Federal, state, tribal and local government agencies, and the community. Consistent with the Recovery Plan, we will implement relevant actions for which we have authority, work cooperatively on implementation of other actions, and encourage other Federal and state agencies to implement recovery actions for which they have responsibility and authority.
In compliance with the requirements of the ESA section 4(f), NMFS is providing public notice and an opportunity to review and comment on the Public Draft Recovery Plan for CC Chinook salmon, and NC and CCC steelhead prior to its final approval.
16 U.S.C. 1531
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; public meeting.
The New England Fishery Management Council (Council) is scheduling a public meeting of its Observer Policy Committee meeting on Thursday, December 17, 2015 to consider actions affecting New England fisheries in the exclusive economic zone (EEZ). Recommendations from this group will be brought to the full Council for formal consideration and action, if appropriate.
This meeting will be held on Thursday, December 17, 2015 at 9 a.m.
The meeting will be held at the Radisson Airport Hotel, 2081 Post Road, Warwick, RI 02886; telephone: (401) 739-3000; fax: (401) 732-9309.
Thomas A. Nies, Executive Director, New England Fishery Management Council; telephone: (978) 465-0492.
The Observer Committee will focus its discussion on the omnibus alternatives in the Omnibus Industry-Funded Monitoring (IFM) Amendment. The Committee may receive a brief update on the revised economic analysis for herring and mackerel alternatives, only if the analysis is sufficiently complete before the meeting date.
Discussion topics include: To review/discuss omnibus alternatives in the IFM Amendment; review primary components to the omnibus alternatives, including standard cost responsibilities, administrative requirements for monitoring service providers, the framework adjustment process, and the prioritization process; review/discuss data utility considerations for observer/at-sea monitoring, portside sampling, and electronic monitoring; review/discuss revised cost assumptions for electronic monitoring and portside sampling; review/discuss the monitoring set-aside option in the IFM amendment. The Committee will also develop recommendations regarding the selection of preferred omnibus alternatives for the omnibus IFM amendment and possibly review revised economic analysis for herring and mackerel alternatives. The Committee may address other business as necessary.
This meeting is physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aids should be directed to Thomas A. Nies, Executive Director, at (978) 465-0492, at least 5 days prior to the meeting date.
16 U.S.C. 1801
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; public hearing (webinar).
The Gulf of Mexico Fishery Management Council (Council) will hold a public hearing to solicit public comments on Electronic Reporting for For-Hire Vessels via webinar.
The webinar will be held Thursday, December 17, 2015, beginning at 6 p.m. and will conclude no later than 9 p.m. Written public comments must be received on or before 5 p.m. E.S.T., Friday, December 18, 2015.
The public documents can be obtained by contacting the Gulf of Mexico Fishery Management Council, 2203 N. Lois Avenue, Suite 1100, Tampa, FL 33607; telephone: (813) 348-1630 or on their Web site at
Dr. John Froeschke, Fishery Biologist/Statistician, Gulf of Mexico Fishery Management Council; telephone: (813) 348-1630; fax: (813) 348-1711; email:
The Council is considering several changes that would require electronic reporting for the Reef Fish and Coastal Migratory Pelagic (CMP) species for the for-hire operators. The agenda for the public hearing/webinar is as follows: Council staff will brief the public on the proposed Amendment then Council staff will open the meeting for questions and public comments.
Register to participate at
Requests for auxiliary aids should be directed to Kathy Pereira (see
16 U.S.C. 1801
10:00 a.m., Friday, December 4, 2015.
Three Lafayette Centre, 1155 21st Street NW., Washington, DC, 9th Floor Commission Conference Room.
Closed.
Surveillance, enforcement, and examinations matters. In the event that the time, date, or location of this meeting changes, an announcement of the change, along with the new time, date, and/or place of the meeting will be posted on the Commission's Web site at
Christopher Kirkpatrick, 202-418-5964.
Under Secretary of Defense for Personnel and Readiness, Department of Defense.
Meeting notice.
The Department of Defense is publishing this notice to announce the following Federal advisory committee meeting of the Defense Advisory Committee on Military Personnel Testing.
Thursday, January 7, 2016, from 9:00 a.m. to 4:00 p.m. and Friday, January 8, 2016, from 9:00 a.m. to 12:00 p.m.
The Pine Inn, Ocean Avenue, between Lincoln and Monte Verde Street, Carmel, California.
Dr. Jane M. Arabian, Assistant Director, Accession Policy, Office of the Under Secretary of Defense for Personnel and Readiness, Room 3D1066, The Pentagon, Washington, DC 20301-4000, telephone (703) 697-9271.
This meeting is being held under the provisions of the Federal Advisory Committee Act of 1972 (title 5, United States Code (U.S.C.), Appendix, as amended), the Government in the Sunshine Act of 1976 (5 U.S.C. 552b, as amended), and 41 CFR 102-3.150.
Public's Accessibility to the Meeting: Pursuant to 5 U.S.C. 552b and 41 CFR 102-3.140 through 102-3.165, and the availability of space, this meeting is open to the public.
Committee's Designated Federal Officer or Point of Contact: Dr. Jane M. Arabian, Assistant Director, Accession Policy, Office of the Under Secretary of Defense for Personnel and Readiness, Room 3D1066, The Pentagon, Washington, DC 20301-4000, telephone (703) 697-9271.
Persons desiring to make oral presentations or submit written statements for consideration at the committee meeting must contact Dr. Jane M. Arabian at the address or telephone number in the
Department of Defense, Defense Security Cooperation Agency.
Notice.
The Department of Defense is publishing the unclassified text of a section 36(b)(1) arms sales notification. This is published to fulfill the requirements of section 155 of Public Law 104-164 dated July 21, 1996.
Sarah A. Ragan or Heather N. Harwell, DSCA/LMO, (703) 604-1546/(703) 607-5339.
The following is a copy of a letter to the Speaker of the House of Representatives, Transmittal 15-76 with attached Policy Justification and Sensitivity of Technology.
(i)
(ii)
(iii)
(iv)
(v)
(vi)
(vii)
* As defined in Section 47(6) of the Arms Export Control Act
(viii)
The Government of the United Kingdom (UK) requested a possible sale of five hundred (500) AGM-114R Hellfire II Semi-Active Laser (SAL) Missiles. The estimated cost is $80 million.
This sale directly contributes to the foreign and national security policies of the United States by enhancing the close air support capability of the UK in support of NATO and other coalition operations. Commonality between close air support capabilities greatly increases interoperability between our two countries' military and peacekeeping forces and allows for greater burden sharing.
The proposed sale improves the UK's ability to meet current and future threats by providing close air support to counter enemy attacks on coalition ground forces in U.S. CENTCOM's area of responsibility. The UK currently has Hellfire missiles in its inventory and will have no difficulty absorbing these additional missiles.
The proposed sale of this equipment and support will not alter the basic military balance in the region.
There is no principal contractor for this sale as the missiles are coming from U.S. Army stock. There are no known offset agreements proposed in connection with this potential sale.
Implementation of this proposed sale will not require the assignment of any additional U.S. Government or contractor representatives to the UK.
There will be no adverse impact on United States defense readiness as a result of this proposed sale. All defense articles and services are approved for release by our foreign disclosure office.
(viii)
1.
2. If a technologically advanced adversary obtained knowledge of the specific 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.
3. A determination has been made that the UK can provide substantially the same degree of protection for the AGM-114R Hellfire II missiles as the United States Government. Transfer of these missiles to the UK is necessary in the furtherance of United States foreign policy and national security objectives.
4. All defense articles and services listed in this transmittal are authorized for release and export to the Government of the United Kingdom.
United States Transportation Command (USTRANSCOM), DoD.
Announcement.
The Department of Defense has rescinded the Defense Transportation Regulation Part IV (Personal Property), (DTR 4500.9R), Appendices in connection with the Defense Personal Property Program (DP3) Phase III Intra-Country Moves (iCM).
Mr. Jim Teague, United States Transportation Command, TCJ4-PI, 508 Scott Drive, Scott Air Force Base, IL 62225-5357; (618) 220-4803.
The following DTR Part IV Appendices have been rescinded:
Intra-Country type personal property shipments will be solicited under SDDC International Tender provisions (
A complete version of the DTR is available via the Internet on the USTRANSCOM homepage at
Defense Security Cooperation Agency, Department of Defense.
Notice.
The Department of Defense is publishing the unclassified text of a section 36(b)(1) arms sales notification. This is published to fulfill the requirements of section 155 of Public Law 104-164 dated July 21, 1996.
Sarah A. Ragan or Heather N. Harwell, DSCA/LMO, (703) 604-1546/ (703) 607-5339.
The following is a copy of a letter to the Speaker of the House of Representatives, Transmittal 15-78 with attached Policy Justification.
(i)
(ii)
(iii)
Eighty-four (84) M 1126 Stryker Infantry Carrier Vehicles (ICV) with the ATK 30mm cannon, the XM813 30mm cannon, or a European variant with the Remote Weapon Station.
Eighty-four (84) M2 Flex Machine Guns.
Also included are the following non-MDE: ICV-30 package including contractor logistics support, support equipment, spare parts, armaments, two (2) AN/PRC-152 Radios per vehicle, one (1) AN/PSN-13 DAGR per vehicle, one (1) VIC-3 per vehicle, training aids/devices/simulators & simulations (TADSS), translated technical manuals with laptop computers, training, Foreign Service Representatives (FSRs), OCONUS Contractor vehicle deprocessing services and technical assistance.
(iv)
(v)
(vi)
(vii)
(viii)
* as defined in Section 47(6) of the Arms Export Control Act.
The Government of Lithuania has requested a sale of eighty-four (84) M 1126 Stryker Infantry Carrier Vehicles (ICV) with the ATK 30mm cannon, the XM813 30mm cannon or a European variant with the Remote Weapon Station and eighty-four (84) M2 Flex Machine Guns. Additionally, they have requested the ICV-30 package, including contractor logistics support, support equipment, spare parts, armaments, two (2) AN/PRC-152 Radios per vehicle, one (1) AN/PSN-13 DAGR per vehicle, one (1) VIC-3 per vehicle, training aids/devices/simulators & simulations (TADSS), translated technical manuals with laptop computers, training, Foreign Service Representatives (FSRs), OCONUS Contractor vehicle deprocessing services and technical assistance. The total estimated value of MDE is $462 million. The overall total estimated value is $599 million.
This proposed sale will contribute to the foreign policy and national security of the United States by helping to improve the security of a NATO ally.
Lithuania's acquisition of the Stryker ICV system would represent a major advancement in capability for the Lithuanian Land Forces, filling a vital capability gap that is not currently addressed. The Stryker ICV system would provide maneuverability, speed, and firepower to the Lithuanian Land Forces and enhance Lithuania's ability to contribute to territorial defense and NATO and coalition operations. Lithuania will have no difficulty absorbing this equipment into its armed forces.
The proposed sale of this equipment and support will not alter the basic military balance in the region.
The principal contractor is unknown at this time. There are no known offset agreements proposed in connection with this potential sale.
Implementation of this proposed sale will require up to 30 U.S. Government or contractor representatives to travel to Lithuania. It is estimated that it will take up to 30 personnel to execute the managing, fielding, training, initial establishment of spare storage and maintenance facilities, and the execution of maintenance over a two-year period, beginning with the first fielding of vehicles.
There will be no adverse impact on U.S. defense readiness as a result of this proposed sale.
(vii)
1. The following Major Defense Equipment items do not contain any sensitive technologies or classified material: 84 Ml 126 Stryker Infantry Carrier Vehicles (ICV) with the ATK 30mm cannon, the XM813 30mm cannon or a European variant with Remote Weapons Station and M2 Flex Machine Guns.
2. The following Non-Major Defense Equipment items that contain sensitive technologies, but no classified material: Support equipment (COMSEC radios and GPS DAGRS). Lithuania is cleared to receive these items. The following Non-Major Defense Equipment items do not contain any sensitive technologies or classified material: Contractor Logistics Support, spare parts, Armaments, Command and Control Communications Computers Intelligence Surveillance and Reconnaissance, Training Aids/Devices/Simulators & Simulations (TADSS), translated technical manuals with laptop computers, training, Foreign Service Representatives, Outside Continental United States Contractor vehicle deprocessing services, and Technical Assistance.
3. A determination has been made that the recipient country can provide the same degree of protection for the sensitive technology being released as the U.S. Government.
4. This sale is necessary in furtherance of the U.S. foreign policy and national security objectives outlined in the Policy Justification. Moreover, the benefits derived from this sale, as outlined in the Policy Justification, outweigh the potential damage that could result is the sensitive technology were revealed to unauthorized persons.
5. All defense articles and services listed in this transmittal have been authorized for release and export to the Government of Lithuania.
Department of Defense, Defense Security Cooperation Agency.
Notice.
The Department of Defense is publishing the unclassified text of a section 36(b)(1) arms sales notification. This is published to fulfill the requirements of section 155 of Public Law 104-164 dated July 21, 1996.
Sarah A. Ragan or Heather N. Harwell, DSCA/LMO, (703) 604-1546/ (703) 607-5339.
The following is a copy of a letter to the Speaker of the House of Representatives, Transmittal 15-60 with attached Policy Justification and Sensitivity of Technology.
(i)
(ii)
(iii)
The Government of Finland has requested a possible sale of forty (40) Guided Multiple Launch Rocket System Pods: Fifteen Pods of M31A1 Unitary Missiles (6 missiles per pod for a total of 90 missiles) and 25 Pods of M30A1 Alternative Warhead Missiles (6 missiles per pod for a total of 150 missiles).
Also included with this request are publications, personnel training and training equipment, software development, U.S. Government and contractor engineering, technical and logistics support services, and other related elements of logistical and program support.
(iv)
(v)
(vi)
(vii)
(viii)
* as defined in Section 47(6) of the Arms Export Control Act
The Government of Finland has requested a possible sale of forty (40) Guided Multiple Launch Rocket Pods: Fifteen Pods of M31A1 Unitary Missiles (6 missiles per pod for a total of 90 missiles) and 25 Pods of M30A1Alternative Warhead Missiles (6 missiles per pod for a total of 150 missiles). Also included are publications, personnel training and training equipment, software development, U.S. Government and contractor engineering, technical and logistics support services, and other related elements of logistical and program support. The total estimated cost is $150 million.
This proposed sale will contribute to the foreign policy and national security objectives of the United States by helping to improve the security of a friendly country which has been, and continues to be, an important force for political stability and economic progress in Europe. The proposed sale of the GMLRS M31A1 Unitary and M30A1 GMLRS Alternative Warhead Rockets will improve Finland's capability to meet current and future threats.
Finland will use this enhanced capability to strengthen and secure its national borders. Finland will have no difficulty absorbing these rocket pods into its armed forces.
The proposed sale of this equipment and support will not alter the basic military balance in the region.
The prime contractor will be Lockheed Martin Missile and Fire Control in Grand Prairie, TX. There are no known offset agreements in connection with this potential sale.
Implementation of this proposed sale will not require the assignment of any additional U.S. or contractor representatives in Finland.
There will be no adverse impact on U.S. defense readiness as a result of this proposed sale.
1. Guided Multiple Launch Rocket System (GMLRS) M31A1 is the Army's primary organic Joint Expeditionary, all-weather, 24/7, tactical GPS PPS precision-guided rocket. M31A1 is the primary rocket for units fielded with the High Mobility Artillery Rocket System (HIMARS) M142 and Multiple Launch Rocket System (MLRS) M270A1 Rocket/Missile Launcher platforms. The M31A1 provides close, medium, and long range precision and area fires to destroy, suppress, and shape threat forces and protect friendly forces. The M31A1 integrates guidance and control packages and an improved rocket motor achieving greater range and precision accuracy. The M31A1 Unitary is the only variant currently in production, integrating a multi-option mode proximity height of burst (HOB) sensor fuze and high explosive warhead making it an all-weather, low collateral damage, precision strike rocket. GMLRS Unitary expands the MLRS/HIMARS target set into urban and complex environments by adding, point, proximity and delay fuzing modes. The highest level of classified information that may be transferred by export of this munition is SECRET.
2. Guided Multiple Launch Rocket System (GMLRS) M30A1 will be the Army's primary organic Joint Expeditionary, all-weather, 24/7, tactical precision guided rocket. The M30A1 Alternative Warhead (AW) will be the primary munition for units fielded with the High Mobility Artillery Rocket System (HIMARS) and Multiple Launch Rocket System (MLRS) M270A1 Rocket/Missile Launcher platforms. M30A1 AW is designed to replace the M26 and M30 Dual Purpose Improved Conventional Munitions (DIPCM), to attack/neutralize/suppress/destroy area and precisely locate targets using indirect precision fires while greatly decreasing the probability of Unexploded Ordinance (UXO). M30A1 AW shares more than 90% commonality with the GMLRS M31A1 Unitary. The commonality includes the motor, GPS PPS inertial guidance and control systems, fuzing mechanisms and proximity multi-option HOB fuze capability. Only the warhead/payload is different. The highest level of classified information that may be transferred by export of this munition is SECRET.
3. All defense articles and services listed in this transmittal have been authorized for release and export to the Government of Finland.
Department of the Navy, DoD.
Notice.
The Department of the Navy hereby gives notice of its intent to grant to Envoy Flight Systems, Inc. located at 201 Ruthar Drive, Suite 3, Newark, Delaware 19711, a revocable, nonassignable, partially exclusive license throughout the United States (U.S.) in the fields of use for Portable Firefighting Systems and Cleaning Systems, but for Spray Cleaning and disinfection of food, flavors, paints, inks and desiccants; and a co-exclusive license throughout the U.S. in the fields of use for Water Desalination and Cleaning Systems for Health Products in the Government-Owned inventions described in U.S. Patent number 5,520,331 issued on May 28, 1996 entitled “Liquid Atomizing Nozzle” and U.S. Patent number 7,523,876 B2 issued on April 28, 2009 entitled “Adjustable Liquid Atomization Nozzle”.
Written objections are to be filed with the Naval Air Warfare Center Aircraft Division, Technology Transfer Office, Attention Michelle Miedzinski, Code 5.0H, 22347 Cedar Point Road, Building 2185, Room 2160, Patuxent River, Maryland 20670.
Anyone wishing to object to the grant of this license must file written objections along with supporting evidence, if any, within fifteen (15) days of the date of this published notice.
Michelle Miedzinski, 301-342-1133, Naval Air Warfare Center Aircraft Division, 22347 Cedar Point Road, Building 2185, Room 2160, Patuxent River, Maryland 20670.
Department of the Navy, DoD.
Notice.
The Department of the Navy herby gives notice of its intent to grant to Lockmasters Incorporated a revocable, nonassignable, exclusive license for three years and a nonexclusive license thereafter to practice in the field of use of security locking devices in the United States and its territories, the Government-owned invention described in U.S. Patent Application 14/826014 entitled “Spindle Locator Tool”, filed on Aug 13, 2015.
Anyone wishing to object to the grant of this license must file written objections along with supporting evidence, if any, not later than [INSERT DATE 15 DAYS AFTER PUBLICATION FIRST APPEARS IN
Written objections should be directed to NAVFAC Engineering & Expeditionary Warfare Center, 1100 23rd Avenue, Port Hueneme, CA 93043-4370.
Victor Cai, Office of Research and Technology Applications, NAVFAC EXWC, 1100 23rd Avenue, Port Hueneme, CA 93043-4370, telephone 805-982-3009, email:
The Spindle Locator Tool enables identification of proper and improper placement of a spindle in a locking mechanism. Specifically, it will be used for the X-10 electromechanical lock which has experienced a spindle and cam interface issue that can result in lockouts requiring neutralization.
(35 U.S.C. 207, 37 CFR part 404)
Department of the Navy, DoD.
Notice; correction.
The Department of the Navy published a document in the
Nora Macariola-See, Naval Facilities Engineering Command, Pacific. Attention: HSTT EIS/OEIS, 258 Makalapa Drive, Suite 100, Pearl Harbor, HI 96860-3134. 808-472-1402.
CORRECTION: In the
Department of the Navy, DoD.
Notice.
Pursuant to 5 U.S.C. 4314(c)(4), the Department of Navy (DON) announces the appointment of members to the DON's numerous Senior Executive Service (SES) Performance Review Boards (PRBs). The purpose of the PRBs is to provide fair and impartial review of the annual SES performance appraisal prepared by the senior executive's immediate and second level supervisor; to make recommendations to appointing officials regarding acceptance or modification of the performance rating; and to make recommendations for performance bonuses and basic pay increases. Composition of the specific PRBs will be determined on an ad hoc basis from among the individuals listed below:
Jacqueline Wourman, Performance Management Program Manager, Executive Management Program Office, Office of Civilian Human Resources at 202 685-6665.
Department of the Navy, DoD.
Notice.
The Department of the Navy hereby gives notice of its intent to grant to CogniTek Management Systems located at 3175 Commercial Avenue, Suite 102, Northbrook, Illinois 60062, a revocable, nonassignable, partially exclusive license throughout the United States (U.S.) in the fields of use for Spray Cleaning and Disinfecting for food, flavors, paints, inks, and desiccants; Fuel Atomization for Combustion, Power Generation and Fuel Production; Water Atomization and Water Evaporation for Heating, Cooling, Humidification and Dehumidification in Heating, Ventilation, and Air Conditioning and Greenhouse applications, as well as Freeze Drying; and a co-exclusive license throughout the U.S. in the fields of use for Water Desalination and Cleaning Systems for Health Products in the Government-Owned inventions described in U.S. Patent number 5,520,331 issued on May 28, 1996 entitled “Liquid Atomizing Nozzle” and U.S. Patent number 7,523,876 B2 issued on April 28, 2009 entitled “Adjustable Liquid Atomization Nozzle”.
Written objections are to be filed with the Naval Air Warfare Center Aircraft Division, Technology Transfer Office, Attention Michelle Miedzinski, Code 5.0H, 22347 Cedar Point Road, Building 2185, Room 2160, Patuxent River, Maryland 20670.
Anyone wishing to object to the grant of this license must file written objections along with supporting evidence, if any, within fifteen (15) days of the date of this published notice.
Michelle Miedzinski, 301-342-1133, Naval Air Warfare Center Aircraft Division, 22347 Cedar Point Road, Building 2185, Room 2160, Patuxent River, Maryland 20670.
35 U.S.C. 207, 37 CFR part 404.
Department of the Navy, DoD.
Notice; correction.
The Department of the Navy published a document in the
Lesley Dobbins-Noble, Naval Facilities Engineering Command, Code EV22LDN (AFTT EIS/OEIS Project Manager), 6506 Hampton Boulevard, Norfolk, Virginia 23508-1278. 757-322-4625.
1. January 12, 2016; and
2. 757-322-4625.
Federal Student Aid (FSA), Department of Education (ED).
Notice.
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 3501
Interested persons are invited to submit comments on or before December 31, 2015.
To access and review all the documents related to the information collection listed in this notice, please use
For specific questions related to collection activities, please contact Beth Grebeldinger, 202-377-4018.
The Department of Education (ED), in accordance with the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3506(c)(2)(A)), provides the general public and Federal agencies with an opportunity to comment on proposed, revised, and continuing collections of information. This helps the Department assess the impact of its information collection requirements and minimize the public's reporting burden. It also helps the public understand the Department's information collection requirements and provide the requested data in the desired format. ED is soliciting comments on the proposed information collection request (ICR) that is described below. The Department of Education 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
National Center for Education Statistics (NCES), Department of Education (ED).
Notice.
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 3501
Interested persons are invited to submit comments on or before December 31, 2015.
Comments submitted in response to this notice should be submitted electronically through the Federal eRulemaking Portal at
For specific questions related to collection activities, please contact Kashka Kubzdela at (202) 502-7411or by email
The Department of Education (ED), in accordance with the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3506(c)(2)(A)), provides the general public and Federal agencies with an opportunity to comment on proposed, revised, and continuing collections of information. This helps the Department assess the impact of its information collection requirements and minimize the public's reporting burden. It also helps the public understand the Department's information collection requirements and provide the requested data in the desired format. ED is soliciting comments on the proposed information collection request (ICR) that is described below. The Department of Education 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.
Office of Science, Department of Energy.
Notice of solicitation for comments.
The President's Council of Advisors on Science and Technology (PCAST) is interested in hearing from stakeholders on a series of questions related to forensic science.
Please submit all responses by December 23, 2015, 12:00 p.m. EST.
input must be submitted electronically using the Web-based form available at
Specific questions about this notice should be sent via email to Ms. Jennifer Michael at
The President's Council of Advisors on Science and Technology (PCAST) is an advisory group of the Nation's leading scientists and engineers, appointed by the President to augment the science and technology advice available to him from inside the White House, Cabinet Departments, and other Federal agencies. See the Executive Order at
Please note that because PCAST operates under the provisions of FACA, all public comments and/or presentations will be treated as public documents and will be made available for public inspection, including being posted on the PCAST Web site.
Office of Energy Efficiency and Renewable Energy, Department of Energy.
Notification of public meeting.
The Department of Energy (DOE) Wind and Water Power Technologies Office (WWPTO) and the Department of the Interior (DOI) Bureau of Ocean Energy Management Office (BOEM) are convening a workshop to obtain individual stakeholder insight into the technical and market challenges and potential pathways to facilitate the development of the offshore wind industry in the United States. The workshop seeks individual input across the range of U.S. offshore wind stakeholders to better inform efforts to update and refine the 2011
DOE and DOI will hold a workshop on Thursday, December 10th, 2015, from 8:00 a.m. to 5:30 p.m. in Washington, DC. RSVP is required by December 7th, 2015.
The workshop will be held at the Hotel Palomar DC located at 2121 P St NW., Washington, DC 20037.
Questions may be directed to Greg Matzat, Department of Energy at (202) 586-2776 or
Since the release of the 2011
The focus of the workshop will be for agencies to receive public input, questions, and recommendations for areas of potential improvement in the refinement and updating of the 2011
It is not the object of this session to obtain any group position or consensus relating to the strategic actions or inactions of the industry as a whole or those of DOE or DOI; rather, the agencies are seeking as much insight as possible from all the individuals at this meeting. To most effectively use the limited time please refrain from passing judgment on another participant's recommendations or advice and, instead, concentrate on your individual experiences.
Take notice that the Commission has received the following Natural Gas Pipeline Rate and Refund Report filings:
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and § 385.214) 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.
Any person desiring to protest in any of the above proceedings must file in accordance with Rule 211 of the Commission's Regulations (18 CFR 385.211) on or before 5:00 p.m. Eastern time on the specified comment date.
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that on November 16, 2015, Magnum Gas Storage, LLC (Magnum), 3165 E. Millrock Dr., #330, Holladay, Utah 84121, filed an application pursuant to section 7(c) of the Natural Gas Act (NGA) and Parts 157 and 284 of the Commission's Regulations requesting that the Commission approve an amendment (Amendment) to the certificate of public convenience and necessity issued to the Magnum in Docket No. CP10-22-000 on March 17, 2011 (March 17 Order). The March 17 Order authorized Magnum to construct facilities in Millard, Juab, and Utah Counties, Utah consisting of four salt caverns, various related aboveground supporting facilities and a 61.6-mile long, 36-inch diameter, header pipeline extending from the storage site to points of interconnection with existing interstate gas transmission facilities owned by Kern River Gas Transmission Company and Questar Pipeline Company near Goshen, Utah.
The Amendment requested by Magnum would authorize the relocation of Magnum's approved natural gas storage caverns and associated surface facilities within the previously analyzed Project area, grant authority to Magnum to provide a new firm wheeling transportation service under market-based rates, and extend the time by which the facilities must be constructed and placed in service. The filing may be viewed on the Web at
Any questions concerning this application should be directed to Tiffany A. James, Vice President, Project Development and Government Affairs, Magnum Gas Storage, LLC, 3165 E. Millrock Dr., #330, Holladay, Utah 84121, telephone: (801) 993-7001, email:
Pursuant to section 157.9 of the Commission's rules, 18 CFR 157.9, within 90 days of this Notice the Commission staff will either: complete its environmental assessment (EA) and place it into the Commission's public record (eLibrary) for this proceeding, or issue a Notice of Schedule for Environmental Review. If a Notice of Schedule for Environmental Review is issued, it will indicate, among other milestones, the anticipated date for the Commission staff's issuance of the final environmental impact statement (FEIS) or EA for this proposal. The filing of the EA in the Commission's public record for this proceeding or the issuance of a Notice of Schedule will serve to notify federal and state agencies of the timing for the completion of all necessary reviews, and the subsequent need to complete all federal authorizations within 90 days of the date of issuance of the Commission staff's FEIS or EA.
There are two ways to become involved in the Commission's review of this project. First, any person wishing to obtain legal status by becoming a party to the proceedings for this project should, on or before the comment date stated below, file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, a motion to intervene in accordance with the requirements of the Commission's Rules of Practice and Procedure (18 CFR 385.214 or 385.211) and the Regulations under the NGA (18 CFR 157.10). A person obtaining party status will be placed on the service list maintained by the Secretary of the Commission and will receive copies of all documents filed by the applicant and by all other parties. A party must submit 5 copies of filings made with the Commission and must mail a copy to the applicant and to every other party in the proceeding. Only parties to the proceeding can ask for court review of Commission orders in the proceeding.
However, a person does not have to intervene in order to have comments considered. The second way to participate is by filing with the Secretary of the Commission, as soon as possible, an original and two copies of comments in support of or in opposition to this project. The Commission will consider these comments in determining the appropriate action to be taken, but the filing of a comment alone will not serve to make the filer a party to the proceeding. The Commission's rules require that persons filing comments in opposition to the project provide copies of their protests only to the party or parties directly involved in the protest.
Persons who wish to comment only on the environmental review of this project should submit an original and two copies of their comments to the Secretary of the Commission. Environmental commenters will be placed on the Commission's environmental mailing list, will receive copies of the environmental documents, and will be notified of meetings associated with the Commission's environmental review process. Environmental commenters will not be required to serve copies of filed documents on all other parties. However, the non-party commenters will not receive copies of all documents filed by other parties or issued by the Commission (except for the mailing of environmental documents issued by the Commission) and will not have the right to seek court review of the Commission's final order.
Motions to intervene, protests and comments may be filed electronically via the Internet in lieu of paper; see, 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's Web site under the “e-Filing” link. The Commission strongly encourages electronic filings.
Comment Date: December 15, 2015
On June 25, 2015, Energy Resources USA Inc., filed an application for a preliminary permit, pursuant to section 4(f) of the Federal Power Act (FPA), proposing to study the feasibility of a hydropower project to be located at the U.S. Army Corps of Engineers' (Corps) David D. Terry Lock and Dam on the Arkansas River near the town of Little Rock in Pulaski County, Arkansas. The sole purpose of a preliminary permit, if issued, is to grant the permit holder priority to file a license application during the permit term. A preliminary permit does not authorize the permit holder to perform any land-disturbing activities or otherwise enter upon lands or waters owned by others without the owners' express permission.
The proposed project would consist of the following: (1) A 100-foot-long overflow bank extension connecting to the existing dam; (2) a 770-foot-long, 200-foot-wide intake channel with a 85-foot-long retaining wall; (3) a 220-foot-long, 90-foot-wide powerhouse containing four generating units with a total capacity of 18 megawatts; (4) a 500-foot-long, 200-foot-wide tailrace with a 85-foot-long retaining wall; (5) a 4.16/69 kilo-Volt (kV) substation; and (6) a 4-mile-long, 69 kV transmission line. The proposed project would have an estimated average annual generation of 128,200 megawatt-hours, and operate as directed by the Corps.
Competing Application: This application competes with Project No. 14664-000 filed March 3, 2015. Competing applications had to be filed on or before July 20, 2015.
Deadline for filing comments and motions to intervene: 60 days from the issuance of this notice. Comments and motions to intervene may be filed electronically via the Internet. See 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's Web site
More information about this project, including a copy of the application, can be viewed or printed on the “eLibrary” link of Commission's Web site at
Take notice that New England Hydropower Company, LLC, permittee for the proposed Lensdale Pond Dam Hydroelectric Project, has requested that its preliminary permit be terminated. The permit was issued on July 25, 2013, and would have expired on June 30,
The preliminary permit for Project No. 14518 will remain in effect until the close of business, December 18, 2015. But, if the Commission is closed on this day, then the permit remains in effect until the close of business on the next day in which the Commission is open.
On June 26, 2015, Arkansas Electric Cooperative Corporation, filed an application for a preliminary permit, pursuant to section 4(f) of the Federal Power Act (FPA), proposing to study the feasibility of a hydropower project to be located at the U.S. Army Corps of Engineers' (Corps) Col. Charles D. Maynard Lock and Dam on the Arkansas River near the town of Pine Bluff in Jefferson County, Arkansas. The sole purpose of a preliminary permit, if issued, is to grant the permit holder priority to file a license application during the permit term. A preliminary permit does not authorize the permit holder to perform any land-disturbing activities or otherwise enter upon lands or waters owned by others without the owners' express permission.
The proposed project would consist of the following: (1) A 100-foot-long overflow bank extension connecting to the existing dam; (2) a 770-foot-long, 300-foot-wide intake channel with a 85-foot-long retaining wall; (3) a 220-foot-long, 90-foot-wide powerhouse containing four generating units with a total capacity of 18 megawatts; (4) a 1000-foot-long, 220-foot-wide tailrace with a 85-foot-long retaining wall; (5) a 4.16/69 kilo-Volt (kV) substation; and (6) a 3-mile-long, 69 kV transmission line. The proposed project would have an estimated average annual generation of 123,700 megawatt-hours, and operate as directed by the Corps.
More information about this project, including a copy of the application, can be viewed or printed on the “eLibrary” link of Commission's Web site at
On March 30, 2015, Lock Hydro Friends Fund III, filed an application for a preliminary permit, pursuant to section 4(f) of the Federal Power Act (FPA), proposing to study the feasibility of a hydropower project to be located at the U.S. Army Corps of Engineers' (Corps) Selden Lock and Dam on the Black Warrior River near the town of Sawyerville in Green and Hale Counties, Alabama. The sole purpose of a preliminary permit, if issued, is to grant the permit holder priority to file a license application during the permit term. A preliminary permit does not authorize the permit holder to perform any land-disturbing activities or otherwise enter upon lands or waters owned by others without the owners' express permission.
The proposed project would consist of the following: (1) A 150-foot-long, 25-foot-wide lock frame module containing ten generating units with a total capacity of 15 megawatts; (2) a 150-foot-long; 65-foot-wide tailrace; (3) a 50-foot-long, 25-foot-wide switchyard; and (4) a 2.3-mile-long, 34.5kV transmission line. The proposed project would have an estimated average annual generation of 78,840 megawatt-hours, and operate as directed by the Corps.
Deadline for filing comments, motions to intervene, competing applications (without notices of intent), or notices of intent to file competing applications: 60 days from the issuance of this notice. Competing applications and notices of intent must meet the requirements of 18 CFR 4.36. Comments, motions to intervene, notices of intent, and competing applications may be filed electronically via the Internet. See 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's Web site
More information about this project, including a copy of the application, can be viewed or printed on the “eLibrary” link of Commission's Web site at
This is a supplemental notice in the above-referenced proceeding Ohio Valley Electric Corporation's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR Part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability, is December 8, 2015.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at
Persons unable to file electronically should submit an original and 5 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The filings in the above-referenced proceeding are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for electronic review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the Web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email
This is a supplemental notice in the above-referenced proceeding RE Astoria 2 LLC's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability, is December 8, 2015.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at
Persons unable to file electronically should submit an original and 5 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The filings in the above-referenced proceeding are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for electronic review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the Web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email
The staff of the Federal Energy Regulatory Commission (FERC or Commission) will prepare an environmental impact statement (EIS) that will discuss the environmental impacts of the Mountaineer XPress Project (MXP) involving construction and operation of facilities by Columbia Gas Transmission, LLC (Columbia) in 14 counties in the western portion of West Virginia. The Commission will use this EIS in its decision-making process to determine whether the project is in the public convenience and necessity.
This notice announces the opening of the scoping process the Commission will use to gather input from the public and interested agencies on the project. You can make a difference by providing us with your specific comments or concerns about the project. Your comments should focus on the potential environmental effects, reasonable alternatives, and measures to avoid or lessen environmental impacts. Your input will help the Commission staff determine what issues they need to evaluate in the EIS. To ensure that your comments are timely and properly recorded, please send your comments so that the Commission receives them in Washington, DC on or before December 17, 2015.
If you sent comments on this project to the Commission before the opening of this docket on September 16, 2015, you will need to file those comments in Docket No. PF15-31-000 to ensure they are considered as part of this proceeding.
This notice is being sent to the Commission's current environmental mailing list for this project. State and local government representatives should notify their constituents of this planned project and encourage them to comment on their areas of concern.
If you are a landowner receiving this notice, a pipeline company representative may contact you about the acquisition of an easement to construct, operate, and maintain the planned facilities. The company would seek to negotiate a mutually acceptable agreement. However, if the Commission approves the project, that approval conveys with it the right of eminent domain. Therefore, if easement negotiations fail to produce an agreement, the pipeline company could initiate condemnation proceedings where compensation would be determined in accordance with state law.
A fact sheet prepared by the FERC entitled “An Interstate Natural Gas Facility On My Land? What Do I Need To Know?” is available for viewing on the FERC Web site (
For your convenience, there are four methods you can use to submit your comments to the Commission. The Commission will provide equal consideration to all comments received, whether filed in written form or provided verbally. The Commission encourages electronic filing of comments and has expert staff available to assist you at (202) 502-8258 or
(1) You can file your comments electronically using the
(2) You can file your comments electronically by using the
(3) You can file a paper copy of your comments by mailing them to the following address. Be sure to reference the project docket number (PF15-31-000) with your submission: Kimberly D. Bose, Secretary, Federal Energy Regulatory Commission, 888 First Street NE., Room 1A, Washington, DC 20426.
(4) In lieu of sending written or electronic comments, the Commission invites you to attend one of the public scoping meetings its staff will conduct in the project area, scheduled as follows.
The doors will open at 5 p.m. at which time we will begin our sign up of speakers for the meetings. For the hour prior to the start of the meetings, Columbia representatives will be present with maps depicting the project and to answer questions.
The scoping meetings will begin at 6 p.m. with a description of our environmental review process by Commission staff, after which speakers will be called. The meetings will end once all speakers have provided their comments or at 10 p.m., whichever comes first. Please note that depending on the number of people signed up to speak, there may be a time limit of 3 minutes to present comments, and speakers should structure their comments accordingly. If time limits are implemented, they will be strictly enforced to ensure that as many individuals as possible are given an opportunity to comment. The meetings will be recorded by a court reporter to ensure comments are accurately recorded. Transcripts will be entered
Please note this is not your only public input opportunity; refer to the review process flow chart in appendix 1.
Columbia plans to construct and operate approximately 167 miles of 36-inch and 24-inch-diameter pipeline; construct three new compressor stations and three regulator stations; and modify three existing compressor stations and other existing appurtenant facilities in West Virginia. The MXP would provide about 2.7 billion standard cubic feet per day of natural gas transportation capacity from production areas to markets on the Columbia system. According to Columbia, its project would enable infrastructure-constrained natural gas supplies to reach waiting markets served by Columbia's system. Columbia has entered into firm contracts for over 88 percent of the MXP capacity.
The MXP would consist of the following facilities:
• Construction of 161.1 miles of new 36-inch-diameter pipeline and associated equipment (main-line valves, pigging facilities,
• construction of 6.3 miles of 24-inch-diamter pipeline in Doddridge County (the Sherwood Lateral);
• construction of three new compressor stations and related equipment in Doddridge County (Sherwood Compressor Station), Ritchie County (White Oak Compressor Station), and Jackson County (Mt. Olive Compressor Station);
• construction of three new regulator stations and associated equipment in Marshall County (the Leach Interconnect), Doddridge County (Sherwood Lateral Regulator), and Cabell County (the Saunders Creek Tie-in);
• replacement of two sections of existing 30-inch-diameter pipeline, 1,295 feet and 814 feet in length, in Cabell County;
• installation of additional compression at the anticipated Lone Oak Compressor Station (Marshall County), Elk River Compressor Station (Wayne County), and Ceredo Compressor Station (Kanawha County)—all of which are under review in other Commission dockets; and
• construction and/or installation of other related equipment.
The general location of the project facilities is shown in appendix 2.
Columbia has proposed to use a 125-foot-wide right-of-way for construction of the new pipeline in upland areas, consisting of a 50-foot-wide permanent and a 75-foot-wide temporary right-of-way, except where site conditions require specific workspace configurations. Temporary right-of-way used during construction would be restored and revert to former uses once construction is completed. However, the permanent right-of-way would be maintained for permanent operation of the MXP.
Additional temporary workspace would be required at road, utility lines, and waterbody crossings; steep slopes; side slopes; horizontal directional drill locations; and at the beginning and end of construction spreads for mobilizing construction equipment. Disturbance would also result from the use of staging areas and construction of new and/or upgrading of existing access roads associated with construction and operation of the planned facilities.
The pipeline would be sited to follow existing pipeline, utility, and road rights-of-way to the maximum extent practicable.
The National Environmental Policy Act (NEPA) requires the Commission to take into account the environmental impacts that could result from an action whenever it considers the issuance of a Certificate of Public Convenience and Necessity. NEPA also requires us
In the EIS, we will discuss impacts that could occur as a result of the construction and operation of the planned project under these general headings:
• Geology and soils;
• land use;
• water resources, fisheries, and wetlands;
• cultural resources;
• vegetation and wildlife;
• socioeconomics;
• air quality and noise;
• endangered and threatened species;
• public safety; and
• cumulative impacts.
We will also evaluate possible alternatives to the planned project or portions of the project, and make recommendations on how to lessen or avoid impacts on the various resource areas.
Although no formal application has been filed, we have already initiated our NEPA review under the Commission's pre-filing process. The purpose of the pre-filing process is to encourage early involvement of interested stakeholders and to identify and resolve issues before the FERC receives an application. As part of our pre-filing review, we have begun to contact some federal and state agencies to discuss their involvement in the scoping process and the preparation of the EIS.
The EIS will present our independent analysis of the issues. We will publish and distribute the draft EIS for public comment. After the comment period, we will consider all timely comments and revise the document, as necessary, before issuing a final EIS. To ensure we have the opportunity to consider and address your comments, please carefully follow the instructions in the Public Participation section, beginning on page 2.
With this notice, we are asking agencies with jurisdiction by law and/or special expertise with respect to the environmental issues related to this project to formally cooperate with us in the preparation of the EIS.
In accordance with the Advisory Council on Historic Preservation's implementing regulations for section 106 of the National Historic Preservation Act, we are using this notice to initiate consultation with the applicable State Historic Preservation Office(s), and to solicit their views and those of other government agencies, interested Indian tribes, and the public on the project's potential effects on historic properties.
We have already identified several issues that we think deserve attention based on a preliminary review of the planned facilities and the environmental information provided by Columbia. This preliminary list of issues may change based on your comments and our analysis.
• Removal of forested areas;
• impacts on endangered and threatened species that not covered under Columbia's Multi-Species Habitat Conservation Plan;
• changes to existing land uses; and
• safety of landowners during the operation of the proposed pipeline.
The environmental mailing list includes federal, state, and local government representatives and agencies; elected officials; environmental and public interest groups; Native American Tribes; other interested parties; and local libraries and newspapers. This list also includes all affected landowners (as defined in the Commission's regulations) who are potential right-of-way grantors, whose property may be used temporarily for project purposes, or who own homes within certain distances of aboveground facilities, and anyone who submits comments on the project. We will update the environmental mailing list as the analysis proceeds to ensure that we send the information related to this environmental review to all individuals, organizations, and government entities interested in and/or potentially affected by the planned project.
Copies of the completed draft EIS will be sent to the environmental mailing list for public review and comment. If you would prefer to receive a paper copy of the document instead of the CD version or would like to remove your name from the mailing list, please return the attached Information Request (appendix 3).
Once Columbia files its application with the Commission, you may want to become an “intervenor” which is an official party to the Commission's proceeding. Intervenors play a more formal role in the process and are able to file briefs, appear at hearings, and be heard by the courts if they choose to appeal the Commission's final ruling. An intervenor formally participates in the proceeding by filing a request to intervene. Motions to intervene are more fully described at
Additional information about the project is available from the Commission's Office of External Affairs at (866) 208-FERC or on the FERC Web site (
In addition, the Commission offers a free service called eSubscription which allows you to keep track of all formal issuances and submittals in specific dockets. This can reduce the amount of time you spend researching proceedings by automatically providing you with notification of these filings, document summaries, and direct links to the documents. Go to
Finally, public meetings or site visits will be posted on the Commission's calendar located at
Take notice that the Commission received the following electric corporate filings:
Take notice that the Commission received the following exempt wholesale generator filings:
Take notice that the Commission received the following electric rate filings:
Description: § 205(d) Rate Filing: 2015-11-20_3rd-4th Quarter Clean-Up Filing to be effective 11/21/2015.
Take notice that the Commission received the following electric securities filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) 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.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission received the following electric rate filings:
Take notice that the Commission received the following electric securities filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) 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.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
This is a supplemental notice in the above-referenced proceeding Cogentrix Virginia Financing Holding Company, LLC's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability, is December 8, 2015.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at
Persons unable to file electronically should submit an original and 5 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The filings in the above-referenced proceeding are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for electronic review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the Web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email
Take notice that the Commission received the following electric rate filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) 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.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
This is a supplemental notice in the above-referenced proceeding Colonial Eagle Solar, LLC's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability, is December 14, 2015.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at
Persons unable to file electronically should submit an original and 5 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The filings in the above-referenced proceeding are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for electronic review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the Web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email
On October 22, 2014, the Federal Energy Regulatory Commission (FERC or Commission) issued in Docket No. PF14-18-000
The October 22, 2014 NOI announced that the FERC will prepare an environmental assessment (EA) to address the environmental impacts of the Northern Access 2016 Project (Project). Please refer to the NOI for more information about the facilities proposed by National Fuel in Pennsylvania and New York. The Commission will use the EA in its decision-making process to determine whether to authorize the Project.
You can make a difference by providing us with your specific comments or concerns about the project. Your comments should focus on the potential environmental effects, reasonable alternatives, and measures to avoid or lessen environmental impacts. Your input will help Commission staff determine what issues they need to evaluate in the EA. To ensure your comments are timely and properly recorded, please send your comments so that the Commission receives them in Washington, DC on or before December 19, 2015.
The Commission previously solicited input on the pipeline portion of the project in Pennsylvania and New York in the fall of 2014. In addition, the Commission solicited input on the aboveground facilities in Niagara County in the spring of 2015. If you have previously submitted comments during the pre-filing review in docket no. PF14-18-000 or since the application filing in docket no. CP15-115-000, you do not need to resubmit your comments at this time. We
This notice is being sent to the Commission's current environmental mailing list for this project. State and local government representatives should notify their constituents of this proposed project and encourage them to comment on their areas of concern.
If you are a landowner receiving this notice, a pipeline company representative may contact you about the acquisition of an easement to construct, operate, and maintain the proposed facilities. The company would seek to negotiate a mutually acceptable agreement. However, if the Commission approves the project, that approval conveys with it the right of eminent domain. Therefore, if easement negotiations fail to produce an agreement, the pipeline company could initiate condemnation proceedings where compensation would be determined in accordance with state law.
National Fuel provided landowners with a fact sheet prepared by the FERC entitled “An Interstate Natural Gas Facility On My Land? What Do I Need To Know?” This fact sheet addresses a number of typically asked questions, including the use of eminent domain and how to participate in the Commission's proceedings. It is also available for viewing on the FERC Web site (
For your convenience, there are three methods you can use to submit your comments to the Commission. The Commission encourages electronic filing of comments and has expert staff available to assist you at (202) 502-8258 or
(1) You can file your comments electronically using the
(2) You can file your comments electronically by using the
(3) You can file a paper copy of your comments by mailing them to the following address. Be sure to reference the project docket number (CP15-115-000) with your submission: Kimberly D. Bose, Secretary, Federal Energy Regulatory Commission, 888 First Street NE., Room 1A, Washington, DC 20426.
Please note this is not your only public input opportunity; please refer to the review process flow chart in appendix 1.
The facilities that are the focus of this notice are the new Pendleton Compressor Station (Killian Road Site) and an additional 2.07 miles of 16- and 14-inch diameter pipeline in the town of Pendleton, New York to connect the new Pendleton Compressor Station to the northward to the existing XM-10 pipeline and southward to the existing X-North Pipeline.
The tie-in between the southern end of Line XM-10 and National Fuel's X-North pipeline in Wheatfield, New York is no longer necessary due to the newly proposed Pendleton Compressor Station site. National Fuel previously proposed to abandon all 3.09 miles of the XM-10 Pipeline system in Wheatfield, New York and Pendleton, New York via sale to Empire. Based on the new location of the Pendleton Compressor Station, Empire would only acquire 1.08 miles of the XM-10 Pipeline system and associated facilities from National Fuel.
The general location of the project facilities is shown in appendix 2.
The National Environmental Policy Act (NEPA) requires the Commission to take into account the environmental impacts that could result from an action whenever it considers the issuance of a Certificate of Public Convenience and Necessity. NEPA also requires us to discover and address concerns the public may have about proposals. This process is referred to as “scoping.” The main goal of the scoping process is to focus the analysis in the EA on the important environmental issues. By this notice, the Commission requests public comments on the scope of the issues to
In the EA we will discuss impacts that could occur as a result of the construction and operation of the proposed project under these general headings:
• Geology and soils;
• Water resources and wetlands;
• Vegetation and wildlife, including migratory birds;
• Fisheries and aquatic resources;
• Threatened, endangered, and other special-status species;
• Land use, recreation, special interest areas, and visual resources;
• Socioeconomics;
• Cultural resources;
• Air quality and noise;
• Reliability and safety; and
• Cumulative environmental impacts.
We will also evaluate reasonable alternatives to the proposed project or portions of the project, and make recommendations on how to lessen or avoid impacts on the various resource areas.
Please note that since the amended application has been filed, an additional docket number has been assigned (CP15-115-001) for the amended Project facilities. As part of our pre-filing review, we participated in public Open House meetings sponsored by National Fuel in the project area in August 2014 to explain the environmental review process to interested stakeholders. We also conducted public scoping meetings of along the proposed pipeline route in November 2014 and in Pendleton, New York in May 2015. We have also contacted federal and state agencies to discuss their involvement in the scoping process and the preparation of the EA.
The EA will present our independent analysis of the issues. We will publish and distribute the EA for public comment. We will consider all comments on the EA before making our recommendations to the Commission. To ensure we have the opportunity to consider and address your comments, please carefully follow the instructions in the Public Participation section, beginning on page 2 of this notice.
With this notice, we are asking agencies with jurisdiction by law and/or special expertise with respect to the environmental issues of this project to formally cooperate with us in the preparation of the EA.
In accordance with the Advisory Council on Historic Preservation's implementing regulations for section 106 of the National Historic Preservation Act, we are using this notice to initiate consultation with the applicable State Historic Preservation Offices (SHPO), and to solicit their views and those of other government agencies, interested Indian tribes, and the public on the project's potential effects on historic properties.
The environmental mailing list includes federal, state, and local government representatives and agencies; elected officials; environmental and public interest groups; Native American Tribes; other interested parties; and local libraries and newspapers. This list also includes all affected landowners (as defined in the Commission's regulations) who are potential right-of-way grantors, whose property may be used temporarily for project purposes, or who own homes within certain distances of aboveground facilities, and anyone who submits comments on the project. We will update the environmental mailing list as the analysis proceeds to ensure that we send the information related to this environmental review to all individuals, organizations, and government entities interested in and/or potentially affected by the proposed project.
Copies of the EA will be sent to the environmental mailing list for public review and comment. If you would prefer to receive a paper copy of the document instead of the CD version or would like to remove your name from the mailing list, please return the attached Information Request (appendix 3).
In addition to involvement in the EA scoping process, you may want to become an “intervenor” which is an official party to the Commission's proceeding. Intervenors play a more formal role in the process and are able to file briefs, appear at hearings, and be heard by the courts if they choose to appeal the Commission's final ruling. An intervenor formally participates in the proceeding by filing a request to intervene. Instructions for becoming an intervenor are in the “Document-less Intervention Guide” under the “e-filing” link on the Commission's Web site. Motions to intervene are more fully described at
Additional information about the project is available from the Commission's Office of External Affairs, at (866) 208-FERC, or on the FERC Web site at
In addition, the Commission offers a free service called eSubscription which allows you to keep track of all formal issuances and submittals in specific dockets. This can reduce the amount of time you spend researching proceedings by automatically providing you with notification of these filings, document summaries, and direct links to the documents. Go to
Finally, public meetings or site visits will be posted on the Commission's calendar located at
Take notice that on November 18, 2015, pursuant to sections 206 and 306 of the Federal Power Act (FPA),
The Complainant certifies that a copy of the complaint has been served on the Respondents.
Any person desiring to intervene or to protest this filing must file in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211, 385.214). Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a notice of intervention or motion to intervene, as appropriate. The Respondent's answer and all interventions, or protests must be filed on or before the comment date. The Respondent's answer, motions to intervene, and protests must be served on the Complainants.
The Commission encourages electronic submission of protests and interventions in lieu of paper using the “eFiling” link at
This filing is accessible on-line at
This is a supplemental notice in the above-referenced proceeding BioUrja Power, LLC's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability, is December 14, 2015.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at
Persons unable to file electronically should submit an original and 5 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The filings in the above-referenced proceeding are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for electronic review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the Web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email
On April 2, 2015, Tennessee Gas Pipeline Company, L.L.C. (TGP) filed an application in Docket No. CP15-148-000 requesting authorization pursuant to section 7(c) of the Natural Gas Act to construct and operate certain natural gas pipeline facilities. The proposed project is known as the Susquehanna West Project (Project), and would deliver an additional 145,000 dekatherms per day of natural gas. According to TGP, its project would meet market needs in the northeast U.S., which have been capacity constrained.
On April 13, 2015, the Federal Energy Regulatory Commission (Commission or FERC) issued its Notice of Application
If a schedule change becomes necessary, additional notice will be provided so that the relevant agencies are kept informed of the Project's progress.
TGP is proposing to construct 8.1 miles of new 36-inch-diameter looping
On June 10, 2015, the Commission issued a
In order to receive notification of the issuance of the EA and to keep track of all formal issuances and submittals in specific dockets, the Commission offers a free service called eSubscription. This can reduce the amount of time you spend researching proceedings by automatically providing you with notification of these filings, document summaries, and direct links to the documents. Go to
Additional information about the Project is available from the Commission's Office of External Affairs at (866) 208-FERC or on the FERC Web site (
Take notice that the Commission received the following electric rate filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
On March 30, 2015, Lock Hydro Friends Fund III, filed an application for a preliminary permit, pursuant to section 4(f) of the Federal Power Act (FPA), proposing to study the feasibility of a hydropower project to be located at the U.S. Army Corps of Engineers' (Corps) Coffeeville Lock and Dam on the Tombigbee River near the town of Coffeeville in Clark and Choctaw Counties, Alabama. The sole purpose of a preliminary permit, if issued, is to grant the permit holder priority to file a license application during the permit term. A preliminary permit does not authorize the permit holder to perform any land-disturbing activities or otherwise enter upon lands or waters owned by others without the owners' express permission.
The proposed project would consist of the following: (1) A 150-foot-long, 25-foot-wide lock frame module containing twelve generating units with a total capacity of 27 megawatts; (2) a 150-foot-long; 65-foot-wide tailrace; (3) a 50-foot-long, 25-foot-wide switchyard; and (4) a 1-mile-long, 34.5kV transmission line. The proposed project would have an estimated average annual generation of 153,738 megawatt-hours, and operate as directed by the Corps.
Deadline for filing comments, motions to intervene, competing applications (without notices of intent), or notices of intent to file competing applications: 60 days from the issuance of this notice. Competing applications and notices of intent must meet the requirements of 18 CFR 4.36. Comments, motions to intervene, notices of intent, and competing applications may be filed electronically via the Internet. See 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's Web site
More information about this project, including a copy of the application, can be viewed or printed on the “eLibrary” link of Commission's Web site at
Take notice that the Commission received the following electric rate filings:
Take notice that the Commission received the following electric reliability filings
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) 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.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
This is a supplemental notice in the above-referenced proceeding Shelby County Energy Center, LLC's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability, is December 14, 2015.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at
Persons unable to file electronically should submit an original and 5 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The filings in the above-referenced proceeding are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for electronic review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the Web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email
The staff of the Federal Energy Regulatory Commission (FERC or Commission) will prepare an environmental assessment (EA) that will discuss the environmental impacts of the Orion Project involving construction and operation of facilities by Tennessee Gas Pipeline Company, L.L.C. (TGP) in Wayne and Pike Counties, Pennsylvania. The Commission will use this EA in its decision-making process to determine whether the project is in the public convenience and necessity.
This notice announces the opening of the scoping process the Commission will use to gather input from the public and interested agencies on the project. You can make a difference by providing us with your specific comments or concerns about the project. Your comments should focus on the potential environmental effects, reasonable alternatives, and measures to avoid or lessen environmental impacts. Your input will help the Commission staff determine what issues they need to evaluate in the EA. To ensure that your comments are timely and properly recorded, please send your comments so that the Commission receives them in Washington, DC on or before December 23, 2015.
If you sent comments on this project to the Commission before the opening of this docket on October 9, 2015, you will need to file those comments in Docket No. CP16-4-000 to ensure they are considered as part of this proceeding.
This notice is being sent to the Commission's current environmental mailing list for this project. State and local government representatives should notify their constituents of this proposed project and encourage them to comment on their areas of concern.
If you are a landowner receiving this notice, a pipeline company representative may contact you about the acquisition of an easement to construct, operate, and maintain the proposed facilities. The company would seek to negotiate a mutually acceptable agreement. However, if the Commission approves the project, that approval conveys with it the right of eminent domain. Therefore, if easement
TGP provided landowners with a fact sheet prepared by the FERC entitled “An Interstate Natural Gas Facility On My Land? What Do I Need To Know?” This fact sheet addresses a number of typically asked questions, including the use of eminent domain and how to participate in the Commission's proceedings. It is also available for viewing on the FERC Web site (
For your convenience, there are three methods you can use to submit your comments to the Commission. The Commission encourages electronic filing of comments and has expert staff available to assist you at (202) 502-8258 or
(1) You can file your comments electronically using the
(2) You can file your comments electronically by using the
(3) You can file a paper copy of your comments by mailing them to the following address. Be sure to reference the project Docket No. (CP16-4-000) with your submission: Kimberly D. Bose, Secretary, Fderal Energy Regulatory Commission, 888 First Street NE., Room 1A, Washington, DC 20426.
TGP proposes to construct and operate pipeline facilities, to modify existing aboveground facilities, and add new tie-in facilities in Wayne and Pike Counties, Pennsylvania. The Orion Project would provide about 135,000 dekatherms per day of natural gas. According to TGP, its project would meet market needs of the Middle Atlantic and New England regions of the United States, and to a lesser extent Canada.
The Orion Project would consist of the following facilities:
• approximately 12.9 miles of new 36-inch-diameter looping
• a new internal pipeline inspection (“pig”) launcher, crossover, and connecting facilities at the beginning of the proposed pipeline loop in Wayne County, Pennsylvania;
• a new “pig” receiver, crossover, and connecting facilities at the end of the proposed pipeline loop in Pike County, Pennsylvania;
• modifications at the existing Compressor Station 323, including rewheeling/restaging of an existing compressor and other piping and appurtenant modifications.
The general location of the project facilities is shown in appendix 1.
Construction of the proposed facilities would disturb about 248 acres of land for the pipeline and aboveground facilities, 62 acres of which are associated with existing permanent TGP rights-of-way. Following construction, TGP would maintain about 79 acres for permanent operation of the project's facilities, 34 acres of which are associated with existing permanent TGP rights-of-way; the remaining acreage would be restored and revert to former uses. The majority of the proposed pipeline route parallels TGP's existing 300 Line rights-of-way. The majority of the aboveground facilities would be constructed within existing facility boundaries or existing permanent easement; however, an additional 0.1 acre of new operational right-of-way would be needed for the proposed aboveground facilities.
The National Environmental Policy Act (NEPA) requires the Commission to take into account the environmental impacts that could result from an action whenever it considers the issuance of a Certificate of Public Convenience and Necessity. NEPA also requires us
In the EA we will discuss impacts that could occur as a result of the construction and operation of the proposed project under these general headings:
• geology and soils;
• land use;
• water resources, fisheries, and wetlands;
• cultural resources;
• vegetation and wildlife;
• air quality and noise;
• endangered and threatened species;
• public safety; and
• cumulative impacts.
We will also evaluate reasonable alternatives to the proposed project or portions of the project, and make recommendations on how to lessen or avoid impacts on the various resource areas.
The EA will present our independent analysis of the issues. The EA will be available in the public record through eLibrary. We will publish and distribute the EA to the public for an allotted comment period. We will consider all comments on the EA before making our recommendations to the Commission. To ensure we have the opportunity to consider and address your comments, please carefully follow the instructions in the Public Participation section, beginning on page 2.
With this notice, we are asking agencies with jurisdiction by law and/or special expertise with respect to the environmental issues of this project to formally cooperate with us in the preparation of the EA.
In accordance with the Advisory Council on Historic Preservation's implementing regulations for section 106 of the National Historic Preservation Act, we are using this
The environmental mailing list includes federal, state, and local government representatives and agencies; elected officials; environmental and public interest groups; Native American tribes; other interested parties; and local libraries and newspapers. This list also includes all affected landowners (as defined in the Commission's regulations) who are potential right-of-way grantors, whose property may be used temporarily for project purposes, or who own homes within certain distances of aboveground facilities, and anyone who submits comments on the project. We will update the environmental mailing list as the analysis proceeds to ensure that we send the information related to this environmental review to all individuals, organizations, and government entities interested in and/or potentially affected by the proposed project.
Copies of the EA will be sent to the environmental mailing list for public review and comment. If you would prefer to receive a paper copy of the document instead of the CD version or would like to remove your name from the mailing list, please return the attached Information Request (appendix 2).
In addition to involvement in the EA scoping process, you may want to become an “intervenor” which is an official party to the Commission's proceeding. Intervenors play a more formal role in the process and are able to file briefs, appear at hearings, and be heard by the courts if they choose to appeal the Commission's final ruling. An intervenor formally participates in the proceeding by filing a request to intervene. Instructions for becoming an intervenor are in the User's Guide under the “e-filing” link on the Commission's Web site.
Additional information about the project is available from the Commission's Office of External Affairs, at (866) 208-FERC, or on the FERC Web site at
In addition, the Commission offers a free service called eSubscription which allows you to keep track of all formal issuances and submittals in specific dockets. This can reduce the amount of time you spend researching proceedings by automatically providing you with notification of these filings, document summaries, and direct links to the documents. Go to
Finally, public meetings or site visits will be posted on the Commission's calendar located at
This is a supplemental notice in the above-referenced proceeding RE Astoria LLC's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability, is December 8, 2015.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at
Persons unable to file electronically should submit an original and 5 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The filings in the above-referenced proceeding are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for electronic review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the Web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email
The Federal Energy Regulatory Commission hereby gives notice that members of the Commission's staff may attend the following meetings related to the transmission planning activities of the PJM Interconnection, L.L.C. (PJM):
The above-referenced meetings will be held at: PJM Conference and Training Center, PJM Interconnection, 2750 Monroe Boulevard, Audubon, PA 19403.
The above-referenced meetings are open to stakeholders.
Further information may be found at
The discussions at the meetings described above may address matters at issue in the following proceedings:
For more information, contact the following:
Environmental Protection Agency (EPA).
Notice of availability.
The Environmental Protection Agency (EPA) is announcing its draft recommended aquatic life water quality criteria for cadmium for public comment. EPA is updating its national recommended ambient water quality criteria for cadmium in order to reflect the latest scientific information, and current EPA policies and methods. Following closure of this public comment period, EPA will consider scientific views from the public on this draft document as well as any new data or information received. EPA will then publish a
Comments must be received on or before February 1, 2016.
Submit your comments, identified by Docket ID No. EPA-HQ-OW-2015-0753, to the
Mike Elias, Health and Ecological Criteria Division, Office of Water (Mail Code 4304T), Environmental Protection Agency, 1200 Pennsylvania Avenue NW., Washington, DC 20460; telephone number: (202) 566-0120; email address:
EPA's recommended water quality criteria are scientifically derived numeric values that protect aquatic life or human health from the deleterious effects of pollutants in ambient water. Section 304(a)(1) of the Clean Water Act (CWA) directs EPA to develop and publish and, from time to time, revise criteria for protection of aquatic life and human health that accurately reflect the latest scientific knowledge. Water quality criteria developed under section 304(a) are based solely on data and the latest scientific knowledge on the relationship between pollutant concentrations and environmental and human health effects. Section 304(a) criteria do not reflect consideration of economic impacts or the technological feasibility of meeting pollutant concentrations in ambient water.
EPA's recommended section 304(a) criteria provide technical information to states and authorized tribes in adopting water quality standards (WQS) that ultimately provide a basis for assessing water body health and controlling discharges or releases of pollutants. Under the CWA and its implementing regulations, states and authorized tribes are to adopt water quality criteria to protect designated uses (
Cadmium is a relatively rare, naturally occurring metal found in mineral deposits and distributed ubiquitously at low concentrations in the environment. Cadmium's primary industrial uses are for the manufacturing of batteries, pigments, plastic stabilizers, metal coatings, alloys and electronics. Recently, cadmium has been used in manufacturing nanoparticles (quantum dots) for use in solar cells and color displays. Cadmium is a non-essential metal with no biological function in aquatic life. Chronic exposure leads to adverse effects on growth, reproduction, immune and endocrine systems, development and behavior in aquatic organisms.
EPA prepared an update of the chronic aquatic life criteria document for cadmium based on the latest scientific information and current EPA policies and methods, including EPA's
The draft estuarine/marine acute criterion for dissolved cadmium is slightly more stringent than the 2001 recommended criterion, which is primarily due to the addition of data. Draft changes in suggested values between 2001 and 2015 can be found in Table 1 below.
EPA will consider the public comments, revise the document as necessary, and issue a final updated cadmium criteria document. This draft criteria document does not represent and should not be construed to represent any final EPA policy, viewpoint, or determination.
As part of the WQS triennial review process defined in section 303(c)(1) of the CWA, the states and authorized tribes are responsible for maintaining and revising WQS. Standards consist of designated uses, water quality criteria to protect those uses, a policy for antidegradation, and may include general policies for application and implementation. Section 303(c)(1) requires states and authorized tribes to review and modify, if appropriate, their WQS at least once every three years.
States and authorized tribes must adopt water quality criteria that protect designated uses. Protective criteria are based on a sound scientific rationale and contain sufficient parameters or constituents to protect the designated uses. Criteria may be expressed in either narrative or numeric form. States and authorized tribes have four options when adopting water quality criteria for
(1) Establish numerical values based on recommended section 304(a) criteria;
(2) Adopt section 304(a) criteria modified to reflect site-specific conditions;
(3) Adopt criteria derived using other scientifically defensible methods; or
(4) Establish narrative criteria where numeric criteria cannot be established or to supplement numerical criteria (40 CFR 131.11(b)).
EPA's regulation at 40 CFR 131.20(a) states that if a state does not adopt new or revised criteria parameters for which EPA has published new or updated recommendations, then the state shall provide an explanation when it submits the results of its triennial review to the Regional Administrator consistent with CWA section 303(c)(1). The recommendations in the draft cadmium criteria document may change based on scientific views shared in response to this notice. Upon finalization, the updated cadmium criteria would supersede EPA's previous 304(a) criteria for cadmium. Consistent with 40 CFR 131.21, new or revised water quality criteria adopted into law or regulation by states and authorized tribes on or after May 30, 2 000 are applicable water quality standards for CWA purposes only after EPA approval.
EPA is soliciting additional scientific views, data, and information regarding the science and technical approach used by the Agency in the derivation of this draft criteria for cadmium. The Agency is also interested in obtaining information regarding new toxicity tests on
EPA conducted a contractor-led and independent external peer review of the draft Aquatic Life Ambient Water Quality Criteria for Cadmium document in October 2015. EPA will make the external peer review comments and Agency responses to these comments available in the docket with the revised draft cadmium criteria document at
Environmental Protection Agency (EPA).
Notice; extension of comment period.
The Environmental Protection Agency (EPA) is extending the comment period for the draft report on the National Wetland Condition Assessment (NWCA 2011). In response to stakeholder requests, the comment period will be extended for an additional 30 days, from December 7, 2015 until January 6, 2016.
Comments must be received on or before January 6, 2016.
Submit your comments, identified by Docket ID No. EPA-HQ-OW-2015-0667, to the
Gregg Serenbetz, Wetlands Division, Office of Water (4502T), Environmental Protection Agency, 1200 Pennsylvania Avenue NW., Washington, DC 20460; telephone number: 202-566-1253; email address:
On November 5, 2015, EPA announced the availability of the draft report,
The original deadline to submit comments on the draft report was December 7, 2015. This action extends the comment period for 30 days. Written comments must now be received by January 6, 2016. The draft report and other supporting materials may also be viewed and downloaded from EPA's Web site at
Environmental Protection Agency (EPA).
Notice of Section 608 Technician Certification Program Test Bank teleconference.
Notice is hereby given that the Stratospheric Protection Division will hold a public teleconference on December 9, 2015 on the Section 608 Technician Certification Test Bank. The teleconference will be an opportunity for stakeholders and members of the public to provide feedback on updating Test Bank questions. For further information regarding the teleconference, please contact Robert Burchard at the number and email below.
The Stratospheric Protection Division will hold a public teleconference on December 9, 2015 from 1 p.m. to 3 p.m. Eastern Standard Time.
• Attaching and detaching hoses and gauges to and from the appliance to measure pressure within the appliance;
• adding refrigerant to or removing refrigerant from the appliance; and
• any other activity that is reasonably expected to violate the integrity of the refrigerant circuit.
The Agency has four types of certification:
• For servicing small appliances (Type I).
• For servicing or disposing of high- or very high-pressure appliances, except small appliances and motor vehicle air conditioning systems (Type II).
• For servicing or disposing of low-pressure appliances (Type III).
• For servicing all types of equipment (Universal).
Technicians are required to pass a test given by an EPA-approved certifying organization to become certified under the program. EPA requires that all test questions come from its Test Bank.
Federal Communications Commission.
Notice and request for comments.
As part of its continuing effort to reduce paperwork burdens, and as required by the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501-3520), the Federal Communications Commission (FCC or Commission) invites the general public and other Federal agencies to take this opportunity to comment on the following information collections. Comments are requested concerning: Whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; the accuracy of the Commission's burden estimate; ways to enhance the quality, utility, and clarity of the information collected; ways to minimize the burden of the collection of information on the respondents, including the use of automated collection techniques or other forms of information technology; and ways to further reduce the information collection burden on small business concerns with fewer than 25 employees. The FCC may not conduct or sponsor a collection of information unless it displays a currently valid Office of Management and Budget (OMB) control number. No person shall be subject to any penalty for failing to comply with a collection of information subject to the PRA that does not display a valid OMB control number.
Written comments should be submitted on or before December 31, 2015. If you anticipate that you will be submitting comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the contacts below as soon as possible.
Direct all PRA comments to Nicholas A. Fraser, OMB, via email
For additional information or copies of the information collection, contact Cathy Williams at (202) 418-2918. To view a copy of this information collection request (ICR) submitted to OMB: (1) Go to the Web page <
In November 2012, FCC modified this collection to include the voluntary requirements of the Rural Microwave Flexibility Policy that were adopted by the FCC on August 3, 2012, the FCC adopted and released a Backhaul Second Report and Order, FCC 12-87, WT Docket No. 10-153. This Policy directs the Wireless Telecommunication Bureau to favorably consider waivers of the requirements for payload capacity of equipment. The voluntary requirements will continue with this PRA collection. There is no change in the third party disclosure requirements.
The Federal Deposit Insurance Corporation (FDIC), as Receiver for 10108 First Coweta Bank, Newnan, GA (Receiver) has been authorized to take all actions necessary to terminate the receivership estate of First Coweta Bank (Receivership Estate); The Receiver has made all dividend distributions required by law.
The Receiver has further irrevocably authorized and appointed FDIC-Corporate as its attorney-in-fact to execute and file any and all documents that may be required to be executed by the Receiver which FDIC-Corporate, in its sole discretion, deems necessary; including but not limited to releases, discharges, satisfactions, endorsements, assignments and deeds.
Effective December 1, 2015 the Receivership Estate has been terminated, the Receiver discharged, and the Receivership Estate has ceased to exist as a legal entity.
The Federal Deposit Insurance Corporation (FDIC), as Receiver for 10040 Pinnacle Bank, Beaverton, OR (Receiver) has been authorized to take all actions necessary to terminate the receivership estate of Pinnacle Bank (Receivership Estate); The Receiver has made all dividend distributions required by law.
The Receiver has further irrevocably authorized and appointed FDIC-Corporate as its attorney-in-fact to execute and file any and all documents that may be required to be executed by the Receiver which FDIC-Corporate, in its sole discretion, deems necessary; including but not limited to releases, discharges, satisfactions, endorsements, assignments and deeds.
Effective December 1, 2015 the Receivership Estate has been terminated, the Receiver discharged, and the Receivership Estate has ceased to exist as a legal entity.
The Federal Deposit Insurance Corporation (FDIC), as Receiver for 10437 Palm Desert National Bank, Palm Desert, CA (Receiver) has been authorized to take all actions necessary to terminate the receivership estate of Palm Desert National Bank (Receivership Estate); The Receiver has
The Receiver has further irrevocably authorized and appointed FDIC-Corporate as its attorney-in-fact to execute and file any and all documents that may be required to be executed by the Receiver which FDIC-Corporate, in its sole discretion, deems necessary; including but not limited to releases, discharges, satisfactions, endorsements, assignments and deeds.
Effective December 1, 2015 the Receivership Estate has been terminated, the Receiver discharged, and the Receivership Estate has ceased to exist as a legal entity.
Board of Governors of the Federal Reserve System.
On June 15, 1984, the Office of Management and Budget (OMB) delegated to the Board of Governors of the Federal Reserve System (Board) its approval authority under the Paperwork Reduction Act (PRA), to approve of and assign OMB numbers to collection of information requests and requirements conducted or sponsored by the Board. Board-approved collections of information are incorporated into the official OMB inventory of currently approved collections of information. Copies of the PRA Submission, supporting statements and approved collection of information instruments are placed into OMB's public docket files. The Federal Reserve may not conduct or sponsor, and the respondent is not required to respond to, an information collection that has been extended, revised, or implemented on or after October 1, 1995, unless it displays a currently valid OMB number.
Comments must be submitted on or before February 1, 2016.
You may submit comments, identified by
• Agency Web site:
• Federal eRulemaking Portal:
• Email:
• FAX: (202) 452-3819 or (202) 452-3102.
• Mail: Robert deV. Frierson, Secretary, Board of Governors of the Federal Reserve System, 20th Street and Constitution Avenue NW., Washington, DC 20551.
All public comments are available from the Board's Web site at
Additionally, commenters may send a copy of their comments to the OMB Desk Officer—Shagufta Ahmed—Office of Information and Regulatory Affairs, Office of Management and Budget, New Executive Office Building, Room 10235 725 17th Street NW., Washington, DC 20503 or by fax to (202) 395-6974.
A copy of the PRA OMB submission, including the proposed reporting form and instructions, supporting statement, and other documentation will be placed into OMB's public docket files, once approved. These documents will also be made available on the Federal Reserve Board's public Web site at:
Federal Reserve Board Clearance Officer—Nuha Elmaghrabi—Office of the Chief Data Officer, Board of Governors of the Federal Reserve System, Washington, DC 20551 (202) 452-3829. Telecommunications Device for the Deaf (TDD) users may contact (202) 263-4869, Board of Governors of the Federal Reserve System, Washington, DC 20551.
The following information collections, which are being handled under this delegated authority, have received initial Board approval and are hereby published for comment. At the end of the comment period, the proposed information collections, along with an analysis of comments and recommendations received, will be submitted to the Board for final approval under OMB delegated authority. Comments are invited on the following:
a. Whether the proposed collection of information is necessary for the proper performance of the Federal Reserve's functions; including whether the information has practical utility;
b. The accuracy of the Federal Reserve's estimate of the burden of the proposed information collection, including the validity of the methodology and assumptions used;
c. Ways to enhance the quality, utility, and clarity of the information to be collected;
d. Ways to minimize the burden of information collection 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.
Proposal to approve under OMB delegated authority the extension for three years, with revision, of the following reports:
1.
Additionally, because all survey respondents are currently registered as bank holding companies, this survey is also authorized under section 5(c) of the Bank Holding Company Act (12 U.S.C. 1844(c)).
Because the release of this information would cause substantial harm to the competitive position of the entity from whom the information was obtained, the information collected on the FR 2436 may be granted confidential treatment under exemption (b)(4) of the Freedom of Information Act, 5 U.S.C. 552(b)(4), which protects from disclosure “trade secrets and commercial or financial information obtained from a person and privileged or confidential.”
The Federal Reserve also proposes to amend the definition of central counterparties in the FR 2436 instructions to align more closely with the definition used in capital regulations.
The Federal Reserve proposes to correct a row heading in Table 5, to update the list of reporting dealers in Annex II, to drop Annex I (a copy of the report form) from the instructions and renumber the remaining annexes, and to make minor corrections to instructions.
2.
Because the Federal Reserve believes the release of this information would cause substantial harm to the competitive position of the entity from whom the information was obtained, the information collected on the FR 3036 may be granted confidential treatment under exemption (b)(4) of the Freedom of Information Act, 5 U.S.C. 552(b)(4), which protects from disclosure “trade secrets and commercial or financial information obtained from a person and privileged or confidential.”
1. For foreign exchange execution methods, FRBNY would separately collect “dark pools” under electronic-indirect trading, and would clarify what would be reported under “Other electronic communication networks.” (Dark pools are private platforms for trading securities especially for large trade sizes, where access is restricted and quotes are not revealed.) The instructions were changed to provide a definition of dark pools, as well as updated guidance on definitions used for the Execution Method schedule.
2. The category “Others” under electronic-indirect trading would be deleted as this item is being deleted by the BIS. The deletion will ensure the FR 3036 aligns with the BIS survey.
3. The questions on algorithmic and high frequency trading would be deleted as this item is being deleted by the BIS. The deletion will ensure the FR 3036 aligns with the BIS survey.
4. The questions on the number of business days, estimated coverage of the survey and concentration levels, and trading activity trends would be deleted. The FRBNY will coordinate responses to these questions with the Secretary of the New York Foreign Exchange Committee and its Operations Subcommittee. This change will allow for an improvement in data quality as it eliminates issues with dealer weighting and poor response rates.
5. The questions on “retail-driven” transactions would be deleted. The FRBNY will coordinate responses to these questions with the Secretary of the New York Foreign Exchange Committee and its Operations Subcommittee. This change will allow for an improvement in data quality as it eliminates issues with dealer weighting and poor response rates.
The notificants listed below have applied under the Change in Bank Control Act (12 U.S.C. 1817(j)) and § 225.41 of the Board's Regulation Y (12 CFR 225.41) to acquire shares of a bank or bank holding company. The factors that are considered in acting on the notices are set forth in paragraph 7 of the Act (12 U.S.C. 1817(j)(7)).
The notices are available for immediate inspection at the Federal Reserve Bank indicated. The notices also will be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing to the Reserve Bank indicated for that notice or to the offices of the Board of Governors. Comments must be received not later than December 15, 2015.
A. Federal Reserve Bank of Minneapolis (Jacquelyn K. Brunmeier, Assistant Vice President) 90 Hennepin Avenue, Minneapolis, Minnesota 55480-0291:
1.
B. Federal Reserve Bank of Dallas (Robert L. Triplett III, Senior Vice President) 2200 North Pearl Street, Dallas, Texas 75201-2272:
1.
The companies listed in this notice have applied to the Board for approval, pursuant to the Bank Holding Company Act of 1956 (12 U.S.C. 1841
The applications listed below, as well as other related filings required by the Board, are available for immediate inspection at the Federal Reserve Bank indicated. The applications will also be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing on the standards enumerated in the BHC Act (12 U.S.C. 1842(c)). If the proposal also involves the acquisition of a nonbanking company, the review also includes whether the acquisition of the nonbanking company complies with the standards in section 4 of the BHC Act (12 U.S.C. 1843). Unless otherwise noted, nonbanking activities will be conducted throughout the United States.
Unless otherwise noted, comments regarding each of these applications must be received at the Reserve Bank indicated or the offices of the Board of Governors not later than December 24, 2015.
A. Federal Reserve Bank of Chicago (Colette A. Fried, Assistant Vice President) 230 South LaSalle Street, Chicago, Illinois 60690-1414:
1.
The companies listed in this notice have given notice under section 4 of the Bank Holding Company Act (12 U.S.C. 1843) (BHC Act) and Regulation Y, (12 CFR part 225) to engage
Each notice is available for inspection at the Federal Reserve Bank indicated. The notice also will be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing on the question whether the proposal complies with the standards of section 4 of the BHC Act.
Unless otherwise noted, comments regarding the notices must be received at the Reserve Bank indicated or the offices of the Board of Governors not later than December 15, 2015.
A. Federal Reserve Bank of Minneapolis (Jacquelyn K. Brunmeier, Assistant Vice President) 90 Hennepin Avenue, Minneapolis, Minnesota 55480-0291:
1.
B. Federal Reserve Bank of Kansas City (Dennis Denney, Assistant Vice President) 1 Memorial Drive, Kansas City, Missouri 64198-0001:
1.
Federal Trade Commission.
Proposed consent agreement.
The consent agreement in this matter settles alleged violations of federal law prohibiting unfair or deceptive acts or practices. The attached Analysis to Aid Public Comment describes both the allegations in the draft complaint and the terms of the consent order—embodied in the consent agreement—that would settle these allegations.
Comments must be received on or before December 28, 2015.
Interested parties may file a comment at
Michael Rose, East Central Region, (216) 263-3412, 1111 Superior Avenue, Suite 200, Cleveland, OH 44114.
Pursuant to Section 6(f) of the Federal Trade Commission Act, 15 U.S.C. 46(f), and FTC Rule 2.34, 16 CFR 2.34, notice is hereby given that the above-captioned consent agreement containing consent order to cease and desist, having been filed with and accepted, subject to final approval, by the Commission, has been placed on the public record for a period of thirty (30) days. The following Analysis to Aid Public Comment describes the terms of the consent agreement, and the allegations in the complaint. An electronic copy of the full text of the consent agreement package can be obtained from the FTC Home Page (for November 24, 2015), on the World Wide Web at:
You can file a comment online or on paper. For the Commission to consider your comment, we must receive it on or before December 28, 2015. Write “Progressive Chevrolet Company and Progressive Motors, Inc.—Consent Agreement; File No. 142 3133” on your comment. Your comment—including your name and your state—will be placed on the public record of this proceeding, including, to the extent practicable, on the public Commission Web site, at
Because your comment will be made public, you are solely responsible for making sure that your comment does not include any sensitive personal information, like anyone's Social Security number, date of birth, driver's license number or other state identification number or foreign country equivalent, passport number, financial account number, or credit or debit card number. You are also solely responsible for making sure that your comment does not include any sensitive health information, like medical records or other individually identifiable health information. In addition, do not include any “[t]rade secret or any commercial or financial information which . . . is privileged or confidential,” as discussed in Section 6(f) of the FTC Act, 15 U.S.C. 46(f), and FTC Rule 4.10(a)(2), 16 CFR 4.10(a)(2). In particular, do not include competitively sensitive information such as costs, sales statistics, inventories, formulas, patterns, devices, manufacturing processes, or customer names.
If you want the Commission to give your comment confidential treatment, you must file it in paper form, with a request for confidential treatment, and you have to follow the procedure explained in FTC Rule 4.9(c), 16 CFR 4.9(c).
Postal mail addressed to the Commission is subject to delay due to heightened security screening. As a result, we encourage you to submit your comments online. To make sure that the Commission considers your online comment, you must file it at
If you file your comment on paper, write “Progressive Chevrolet Company and Progressive Motors, Inc.—Consent Agreement; File No. 142 3133” on your comment and on the envelope, and mail your comment to the following address: Federal Trade Commission, Office of the Secretary, 600 Pennsylvania Avenue NW., Suite CC-5610 (Annex D), Washington, DC 20580, or deliver your comment to the following address: Federal Trade Commission, Office of the Secretary, Constitution Center, 400 7th Street SW., 5th Floor, Suite 5610 (Annex D), Washington, DC 20024. If possible, submit your paper comment to the Commission by courier or overnight service.
Visit the Commission Web site at
The Federal Trade Commission (“FTC”) has accepted, subject to final approval, an agreement containing a consent order from Progressive Chevrolet Company and Progressive Motors, Inc. The proposed consent order has been placed on the public record for thirty (30) days for receipt of comments by interested persons. Comments received during this period will become part of the public record. After thirty (30) days, the FTC will again review the agreement and the comments received, and will decide whether it should withdraw from the agreement and take appropriate action or make final the agreement's proposed order.
The respondents are motor vehicle dealers. According to the FTC complaint, respondents advertised that consumers could lease the advertised vehicles at the monthly payment amounts prominently stated in their advertisements. The complaint alleges that respondents violated Section 5(a) of the Federal Trade Commission Act, 15 U.S.C. 45(a), because they failed to disclose, and/or failed to disclose adequately, that the offer requires a minimum credit score that is greater than the credit score of the majority of consumers. This information would be material to consumers in deciding whether to visit respondents' dealerships and/or whether to lease an automobile from respondents. The complaint also alleges that respondents' leasing advertisements violated the Consumer Leasing Act (CLA) and Regulation M by failing to disclose or to disclose clearly and conspicuously required terms. Specifically, respondents' advertisements prominently stated the monthly payment amounts for a vehicle lease—a triggering term under the CLA—but failed to disclose, or inconspicuously disclosed at the bottom of the ad in much smaller type, the required information set forth by the CLA. The proposed order is designed to prevent the respondents from engaging in similar deceptive practices in the future.
• Part I.A. addresses the Section 5 allegation by prohibiting respondents from advertising the amount of any monthly payment, periodic payment, initial payment, or down payment, or the length of payment term, unless the representation is non-misleading, and respondents clearly and conspicuously disclose all qualifications or restrictions on the consumer's ability to obtain the represented terms, including qualifications or restrictions based on the consumer's credit score. Additionally, if a majority of consumers likely will not be able to meet a credit score qualification or restriction stated in the advertisement, respondents must clearly and conspicuously disclose that fact.
• Part I.B.1. provides that the respondents shall not misrepresent the cost of financing the purchase of an automobile, including by misrepresenting the amount or percentage of the down payment, the number of payments or period of repayment, the amount of any payment, and the repayment obligation over the full term of the loan, including any balloon payment.
• Part I.B.2. provides that the respondents shall not misrepresent the cost of leasing an automobile, including by misrepresenting the total amount due at lease inception, the down payment, amount down, acquisition fee, capitalized cost reduction, any other amount required to be paid at lease inception, and the amounts of all monthly or other periodic payments.
• Part I.C. provides that the respondents shall not misrepresent any other material fact about the price, sale, financing, or leasing of any automobile.
• Part II of the order addresses the CLA and Regulation M allegations by prohibiting lease advertisements that:
A. State the amount of any payment or that any or no initial payment is required at lease inception, without disclosing clearly and conspicuously the following terms:
○ That the transaction advertised is a lease;
○ The total amount due prior to or at consummation or by delivery, if delivery occurs after consummation;
○ the number, amounts, and timing of scheduled payments;
○ whether or not a security deposit is required; and
○ that an extra charge may be imposed at the end of the lease term where the consumer's liability (if any) is based on the difference between the residual value of the leased property and its realized value at the end of the lease term.
B. Fail to comply in any respect with Regulation M, 12 CFR part 213, as amended, and the Consumer Leasing Act, 15 U.S.C. 1667-1667f, as amended.
• Part III requires respondents to keep copies of relevant advertisements and materials containing representations.
• Part IV requires that respondents provide copies of the order to certain of their personnel.
• Part V requires notification to the Commission regarding changes in corporate structure that might affect compliance obligations under the order. Part VI requires the respondents to file compliance reports with the Commission. Finally, Part VII is a provision “sunsetting” the order after twenty (20) years, with certain exceptions.
The purpose of this analysis is to aid public comment on the proposed order. It is not intended to constitute an official interpretation of the complaint or proposed order, or to modify in any way the proposed order's terms.
By direction of the Commission.
In accordance with Presidential Executive Order No. 13175, November 6, 2000, and the Presidential Memorandum of November 5, 2009, and September 23, 2004, Consultation and Coordination with Indian Tribal Governments, CDC/Agency for Toxic Substances and Disease Registry (ATSDR), announces the following meeting and Tribal Consultation Session:
During the 14th Biannual Tribal Consultation Session, tribes and CDC leaders will engage in a listening session with CDC's director and roundtable discussions with CDC senior leaders. Tribes will also have an opportunity to present testimony about tribal health issues.
Tribal leaders are encouraged to submit written testimony by January 8, 2016, to Alleen R. Weathers, Public Health Advisor for the Tribal Support Unit, OSTLTS, via mail to 4770 Buford Highway NE., MS E-70, Atlanta, Georgia, 30341-3717, or email
Based on the number of tribal leaders giving testimony and the time available, it may be necessary to limit the time for each presenter.
The agenda is subject to change as priorities dictate.
Information about the TAC, CDC/ATSDR's Tribal Consultation Policy, and previous meetings can be found at the following Web link:
Contact person for more information: Alleen R. Weathers, Public Health Advisor, CDC/OSTLTS, 4770 Buford Highway NE., MS E-70, Atlanta, Georgia 30341-3717; email:
The Director, Management Analysis and Services Office, has been delegated the authority to sign
Centers for Medicare & Medicaid Services (CMS), HHS.
Notice with comment period.
In accordance with the Court's October 6, 2015 order in
In commenting, refer to file code CMS-1658-NC. Because of staff and resource limitations, we cannot accept comments by facsimile (FAX) transmission.
You may submit comments in one of four ways (please choose only one of the ways listed):
1.
2.
Please allow sufficient time for mailed comments to be received before the close of the comment period.
3.
4.
a. For delivery in Washington, DC—Centers for Medicare & Medicaid Services, Department of Health and Human Services, Room 445-G, Hubert H. Humphrey Building, 200 Independence Avenue SW., Washington, DC 20201.
(Because access to the interior of the Hubert H. Humphrey Building is not readily available to persons without Federal government identification, commenters are encouraged to leave their comments in the CMS drop slots located in the main lobby of the building. A stamp-in clock is available for persons wishing to retain a proof of filing by stamping in and retaining an extra copy of the comments being filed.)
b. For delivery in Baltimore, MD—Centers for Medicare & Medicaid Services, Department of Health and Human Services, 7500 Security Boulevard, Baltimore, MD 21244-1850.
If you intend to deliver your comments to the Baltimore address, call telephone number (410) 786-9994 in advance to schedule your arrival with one of our staff members.
Comments erroneously mailed to the addresses indicated as appropriate for hand or courier delivery may be delayed and received after the comment period.
For information on viewing public comments, see the beginning of the
Ing-Jye Cheng, (410) 786-2260 or Don Thompson, 410-786-6504.
Comments received timely will also be available for public inspection as they are received, generally beginning approximately 3 weeks after publication of a document, at the headquarters of the Centers for Medicare & Medicaid Services, 7500 Security Boulevard, Baltimore, Maryland 21244, Monday through Friday of each week from 8:30 a.m. to 4 p.m. e.s.t. To schedule an appointment to view public comments, phone 1-800-743-3951.
In the final rule titled “Medicare Program; Hospital Inpatient Prospective Payment Systems for the Acute Care Hospitals and the Long-Term Care Hospital Prospective Payment System and Final Fiscal Year 2014 Rates; Quality Reporting Requirements for Specific Providers; Hospital Conditions of Participation; Payment Policies Related to Patient Status” (hereinafter referred to as the FY 2014 IPPS/LTCH PPS final rule), we adopted the 2-midnight policy effective October 1, 2013 (78 FR 50906 through 50954). Under the 2-midnight policy, an inpatient admission is generally appropriate for Medicare Part A payment if the physician (or other qualified practitioner) admits the patient as an inpatient based upon the expectation that the patient will need hospital care that crosses at least 2 midnights. In assessing the expected duration of necessary care, the physician (or other practitioner) may take into account outpatient hospital care received prior to inpatient admission. If the patient is expected to need less than 2 midnights of care in the hospital, the services furnished should generally be billed as outpatient services. Our actuaries estimated that the 2-midnight policy would increase expenditures by approximately $220 million in FY 2014 due to an expected net increase in inpatient encounters. We used our authority under section 1886(d)(5)(I)(i) of the Act to make a reduction of 0.2 percent to the standardized amount, the Puerto Rico standardized amount, and the hospital-specific payment rate, and we used our authority under section 1886(g) of the Act to make a reduction of 0.2 percent to the national capital Federal rate and the Puerto Rico-specific capital rate, in order to offset this estimated $220 million in additional IPPS expenditures in FY 2014. (In addition to an operating IPPS payment for each discharge, hospitals also receive a capital IPPS payment for each discharge so a net increase in the number of inpatient encounters also results in increased expenditures under the capital IPPS.)
As noted in section I. of this notice with comment period, we estimated based on an actuarial model that the 2-midnight policy would increase IPPS expenditures by approximately $220 million in FY 2014 due to an expected net increase in inpatient encounters, as described in greater detail in an August 19, 2013 memorandum. (See Appendix A of this notice.)
Section II.B. of this notice with comment period provides additional details on the calculation of this estimate (that is, what we did) and section II.C. of this notice with comment period discusses the actuaries' assumptions, including why those assumptions were reasonable. We collectively refer to the calculations and assumptions as the actuarial “model” for estimating the financial impact of the policy change. Section II.D. of this notice with comment period discusses the status of an analysis currently being conducted by our actuaries of the claims experience since the implementation of the 2-midnight policy. We seek comment on all aspects of the model used by our actuaries, including but not limited to those for which we specifically request comment. We seek comment on, and will consider comments on, all aspects of the 0.2 percent reduction.
The task of modeling the impact of the 2-midnight policy on hospital payments begins with a recognition that some cases that were previously outpatient cases will become inpatient cases and vice versa. Therefore, our actuaries were required to develop a model that determined the net effect of the number of cases that would move in each direction.
In estimating the number of outpatient cases that would shift to the inpatient setting, we analyzed calendar year (CY) 2011 claims that included spending for observation care or a major procedure. For the purposes of the −0.2 percent estimate, CMS physicians defined observation care as Outpatient Prospective Payment System (OPPS) claims containing Healthcare Common Procedure Coding System (HCPCS) code “G0378”,
A list of the Ambulatory Payment Classifications (APCs) containing the major procedures used in the determination of the −0.2 percent estimate can be found in Appendix B of this notice with comment period. As with observation care, the difference between the first date of service for the HCPCS code and the claim through date was used to determine the length of the major procedure. We identified approximately 50,000 claims containing major procedures with stays lasting 2 midnights or more using the CY 2011 claims.
Combining the observation care and the major procedures resulted in approximately 400,000 claims for services of 2 midnights or more from the CY 2011 claims data.
For additional details on the identification of the outpatient claims, see Appendix C of this notice with comment period.
In estimating the number of inpatient stays that would shift to the outpatient setting, FY 2011 inpatient claims containing a surgical Medicare Severity Diagnosis Related Group (MS-DRG) were analyzed. The number of these stays that spanned less than 2 midnights, based on the length of stay, was approximately 360,000. FY 2009 and FY 2010 data were also analyzed and the results were consistent with the FY 2011 results.
For additional details on the identification of the inpatient claims, see Appendix D of this notice with comment period.
Our actuaries also assumed that payment under the OPPS would be 30 percent of the payment under the IPPS for encounters shifting between the two systems, and that the beneficiary is responsible for 20 percent of the Part B cost.
The number of short stay discharges (for this purpose, same day discharges and discharges crossing one or two midnights) represented about 28 percent of total discharges in FY 2011, and approximately 17 percent of total spending for the total discharges. The assumed net increase of 40,000
For the outpatient expenditure estimate, taking 30 percent (based on the assumption that payment under the OPPS would be 30 percent of the payment under the IPPS) of 80 percent (to account for the assumed 20 percent beneficiary responsibility) of the $290 million inpatient estimate results in approximately $70 million less outpatient expenditures. The estimates for the reduction in outpatient expenditures for FYs 2015 through 2018 can also be found in the table (For example, $80 million for FY 2015.)
The estimated $290 million increase in inpatient expenditures less the estimated $70 million decrease in outpatient expenditures yields the estimated net impact by our actuaries at the time of the FY 2014 IPPS/LTCH PPS rulemaking of an additional $220 million in expenditures in FY 2014 as a result of the 2-midnight policy. The estimated additional expenditures for FYs 2015 through 2018 can be similarly calculated.
Using the information contained in this section and the appendices to this notice, interested members of the public should be able to calculate the estimate by our actuaries of an additional $220 million in expenditures in FY 2014 as a result of the 2-midnight policy. (For interested members of the public who wish to perform this calculation, we highlight the discussion in Appendix D regarding the number of inpatient cases identified in the MedPAR data and the Integrated Data Repository.)
As our actuaries stated in the August 2013 memorandum, the estimates depend critically on the assumed utilization changes in the inpatient and outpatient hospital settings. We discuss the assumptions underlying the estimates further in this section.
As indicated previously, in estimating the number of outpatient cases that would shift to the inpatient setting, CY 2011 claims that included spending for observation care or a major procedure were analyzed. This was done in order to remove claims with diagnostic services or minor procedures that would be less likely to trigger an encounter in which there was a continuous stay. (See the discussion in Appendix C of this notice with comment period.)
For the purpose of the −0.2 percent estimate, observation care was defined as OPPS claims containing HCPCS “G0378,”
However, in retrospect, using HCPCS G0378 and G0379 may have been an overly conservative definition of observation services, because not every use of observation services would be captured by the G-codes. As indicated in the Medicare Claims Processing Manual,
We also note that the Office of the Inspector General (OIG) used this revenue center code definition of observation services in its report “Hospitals' Use of Observation Stays and Short Inpatient Stays
If we had defined observation services using revenue center codes 0760 and 0762 instead of HCPCS codes G0378 and G0379, we would have identified approximately 400,000 claims for observation services spanning 2 midnights or more (instead of 350,000) and we would have estimated approximately 450,000 cases shifting from the outpatient to the inpatient setting (400,000 claims for observation stays spanning more than 2 midnights and approximately 50,000 claims for major procedures) instead of the 400,000 cases used in the estimate. We seek comment on whether it would be more appropriate to define observation services using revenue center codes 0760 and 0762 rather than HCPCS codes G0378 and G0379.
Another consequence of the use of the claims analyses that we developed for the purpose of the comprehensive APCs involves the approach used to determine whether observation stays spanned 2 midnights or more. In general, in the claims analysis for comprehensive APC development, we examined the difference between the date of service for the primary HCPCS code on the claim and the claim through date. For the observation services in this analysis, we used the difference between first date of service for the observation service and the claim through date to determine the length of the observation case. However, in retrospect, as with the definition of observation services, this may have been an overly conservative approach to determining the length of the observation case. Under the 2-midnight policy, for purposes of determining whether the 2 midnight benchmark was met and, therefore, whether inpatient admission was generally appropriate, the expected duration of care includes the time the beneficiary spent receiving outpatient services within the hospital. This includes services such as observation services, treatments in the emergency department, and procedures provided in the operating room or other treatment area. It is not just the time spent receiving observation services. As such, it may have been more appropriate to have used the “claim from” date (in general the date that the beneficiary entered the hospital), rather than the first date that observation services were provided in order to determine when claims containing observation services spanned 2 midnights or more. If we had used such an approach when developing the original estimate, instead of approximately 350,000 claims with observation services spanning 2
We believed some proportion of the inpatient cases under 2 midnights in the historical data would remain inpatient because we believed that behavioral changes by hospitals and admitting practitioners would mitigate some of the impact of cases shifting between the inpatient hospital setting and the outpatient hospital setting. The question was how to reasonably estimate what that proportion would be for purposes of modelling the impact of the 2-midnight policy. We believe that a model distinguishing between medical and surgical cases is a reasonable approach to use in determining what proportion of inpatient cases would remain in the inpatient setting and what proportion would shift to the outpatient setting.
Specifically, in estimating the number of inpatient stays that would shift to the outpatient setting, FY 2011 inpatient claims containing a surgical MS-DRG were analyzed. Our actuaries assumed that those spanning less than 2 midnights (other than those stays that were cut short by a death or transfer) would shift from the inpatient setting to the outpatient setting. Stays that were cut short by a death or transfer were excluded because under the 2-midnight policy those cases would generally be considered to be appropriately treated on an inpatient basis. (For a discussion of the data specifications for the inpatient claims analysis, see Appendix D of this notice.)
Claims containing medical MS-DRGs were excluded because, as stated in the August 2013 memorandum, “it was assumed that these cases would be unaffected by the policy change.” Our actuaries excluded medical MS-DRGs when developing the −0.2 percent estimate because they believed that due to behavioral changes by hospitals and admitting practitioners most inpatient medical encounters spanning less than 2 midnights before the current 2-midnight policy was implemented might be reasonably expected to extend past 2 midnights after its implementation and would thus still be considered inpatient. They believed that the clinical assessments and protocols used by physicians to develop an expected length of stay for medical cases were, in general, more variable and less defined than those used to develop an expected length of stay for surgical cases.
Evidence of this medical/surgical dichotomy is seen in proprietary utilization review tools such as the Milliman Care Guidelines, which are guidelines based originally on actuarial data, and InterQual, which are clinically oriented guidelines. Both tools reflect the same types of distinctions between medical and surgical cases that we assumed based on CMS medical staff's clinical judgment. Although all guidelines, and all surgeons, advise patients that individual patients vary in their post-operative courses, there are predictable post-operative courses that are based on such factors as whether or not the abdominal cavity or the pleural cavity are entered, the expected time for recovery from anesthesia, the expected time to resume urinary function, the expected time to resume bowel function, the expected time to regain mobility, and the typical period for common post-operative interventions. These are by no means absolute but are fairly well-defined, as evidenced by the surgeon's ability to generally inform the patient, within a day or so, how long the patient probably can expect to remain in the hospital if treatment goes well. Part of this decreased variance is due to the fact that the reason for admission, a specific surgical procedure, is well-defined.
Conversely, for medical admissions a single diagnosis typically covers a much broader spectrum of possibilities. Pneumonia may have different etiologies, with vastly different expected lengths of stay. A stroke may be minor, allowing a brief diagnostic workup to be followed by outpatient rehabilitation, or catastrophic, triggering a prolonged stay before stabilization and discharge. Chronic obstructive pulmonary disease (COPD) and congestive heart failure (CHF) may respond rapidly to medication adjustments or may result in Intense Care Unit (ICU) stays. Unlike the surgical procedure, the medical diagnosis does not imply a reasonably consistent set of activities. In fact, typical medical protocols are highly branched, with the initial portion of hospital care typically focused on diagnostics that serve to differentiate patient subsets that define treatments and simultaneously suggest different hospital courses. The increased variability in the medical protocols is influenced by the fact that, for planned surgical admissions, more of the branching takes place in the process of selecting a specific surgical intervention before the patient is admitted, while for medical admissions more of the branching takes place after admission.
For these reasons, the clinical judgment of CMS's medical staff supports our actuaries' estimate of the impact of the 2-midnight policy on program payments to hospitals.
Our actuaries assumed that the OPPS cost for services that shift between the OPPS and IPPS was 30 percent of the IPPS cost, and the beneficiary is responsible for 20 percent of the OPPS cost. The 30 percent is an assumption about the difference on average. While payment under the OPPS is on average less than payment under the IPPS for these cases, the key question is how much less on average? For any given case, the payment differential will vary. We note that when the OIG examined the payment differential between short inpatient stays and observation stays in their 2013 report “Hospitals' Use of Observation Stays and Short Inpatient Stays for Medicare Beneficiaries” (OEI-02-12-00040), it found that on average Medicare paid nearly three times more for a short inpatient stay than an observation stay (p. 12). This is consistent with the 30 percent estimate used in the development of the −0.2 percent estimate. We seek comment on whether it is appropriate to utilize a 30 percent estimate.
Our actuaries are currently conducting an analysis of claims experience for FY 2014 and FY 2015 in light of available data, including the MedPAR data. Because that analysis is not yet complete, we are not proposing in this notice with comment period to reconsider the 0.2 percent reduction in the FY 2014 IPPS/LTCH PPS final rule based on the results of the claims analysis. However, we are seeking comment on whether we should await the completion of the actuaries' analysis of FY 2014 and FY 2015 data before resolution of this proceeding.
We note that any potential model revisions do not necessarily mean that the net result of the initial modelling, namely the ultimate −0.2 percent adjustment, was incorrect. As we have indicated since the −0.2 percent estimate was developed, the assumptions used for purposes of reasonably estimating overall impacts cannot be construed as absolute statements about every individual encounter. Under the original 2-midnight policy, our actuaries did not expect that every single surgical MS-DRG encounter spanning less than 2 midnights would shift to the outpatient setting, that every single medical MS-DRG encounter would remain in the inpatient setting, and that every single outpatient observation stay or major surgical encounter spanning more than 2 midnights would shift to the inpatient setting. However, for purposes of developing the −0.2 percent adjustment estimate under the original policy, a model where cases involving a surgical MS-DRG spanning less than 2 midnights in the historical data shifted to the outpatient setting, cases involving a medical MS-DRG spanning less than 2 midnights in the historical data remained in the inpatient setting, and outpatient observation stays and major surgical encounters spanning more than 2 midnights in the historical data shifted to the inpatient setting yielded a reasonable estimate of the net effect of the 2-midnight policy when it was adopted. To the extent the actual experience might vary for each of the individual assumptions, our actuaries estimated that the total net effect of that variation would not significantly impact the estimate.
There were also factors that could not be anticipated at the time of the initial modelling that may influence the actual experience, such as the prohibition on Recovery Auditor post-payment reviews that became effective October 1, 2013. This prohibition might have affected hospital behavior in unexpected ways.
Our actuaries will continue to review the claims experience for FY 2014 and subsequent years under the 2-midnight policy to evaluate the assumptions underlying the original estimate. As we indicated in the CY 2016 OPPS/ASC final rule, we will take the reviews into account during future rulemaking, including potential future rulemaking on the issue of whether or not the policy change that we adopted for the medical review of inpatient hospital admissions under Medicare Part A described in the CY 2016 OPPS final rule will have a differential impact on expenditures compared to the original policy. Although our analysis of the historical data since the implementation of the 2-midnight policy is not yet complete, and we do not propose to reconsider the reduction in light of that analysis at this time, we are including this discussion in this notice because we received many comments on the CY 2016 OPPS proposed rule asserting that the claims data since the adoption of the original 2-midnight policy is inconsistent with our original −0.2 percent estimate. We continue to invite comment on this issue. As indicated in the CY 2016 OPPS final rule, we intend to respond to all public comments regarding the validity of the original −0.2 percent adjustment that we received in response to the CY 2016 OPPS proposed rule as part of these Shands remand proceedings and publish a final notice by March 18, 2016.
We elected to promulgate the -0.2 percent adjustment for the reasons described in the FY 2014 IPPS/LTCH PPS proposed and final rules and elaborated upon in this notice with comment period. We request comment on all aspects of that decision, including but not limited to the information, assumptions, and analyses supporting the adjustment.
This document does not impose information collection requirements, that is, reporting, recordkeeping or third-party disclosure requirements. Consequently, there is no need for review by the Office of Management and Budget under the authority of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
Because of the large number of public comments we normally receive on
This Appendix provides additional detail on how we identified outpatient claims for observation services or a major procedure spanning 2 midnights or more for purposes of estimating the shift in outpatient cases.
The comprehensive APC analysis that also formed the basis for the 2 midnight analysis was performed using 2011 OPPS claims of bill type 13x extracted from the Standard Analytic File processed through December 31, 2011 with service line charges converted to costs per the usual OPPS cost modeling logic. (A description of the cost modeling logic can be found in the claims accounting document for each year of OPPS rulemaking and is available on our Web site at
Hospital OP claims do not readily distinguish between claims based on services provided while the beneficiary physically stayed at the hospital and claims where the beneficiary received recurring services on successive days while leaving the hospital between services. Since only continuous stays apply for this analysis, certain assumptions had to be made to indirectly estimate the body of claims for continuous stays. Claims were trimmed to only those whose full span of coverage (the difference of claim-through-date and claim-from-date) was less than 7 days. Claims with longer than a 7 day span were excluded as unlikely to represent continuous overnight stays. Claims were then subset to those containing observation services or a significant procedure, as observation services are reported differently in those two subgroups. To further remove recurring services during this subsetting, claims that did not fall into one of the following were removed from the analysis:
• Claims containing G0378 (“Hospital observation per hr”) and a medical visit procedure code (status indicator of “V”);
• Claims containing G0379 (“Direct refer hospital observ”), considered to be “medical claims;”
• Claims containing a significant OPPS procedure code (status indicator of “S” or “T”) that received Medicare payment, considered to be “surgical claims.”
Next, the highest cost coded services on non-observation claims (those without G0379 or without G0378 and a medical visit procedure) were identified. Non-observation claims where the highest cost procedure was not a C-code (Temporary Hospital Outpatient PPS), a J-code (non-orally administered medication and chemotherapy drugs), a significant OPPS procedure code (status indicator of “S” or “T”), or a medical visit procedure code (status indicator of “V”) were removed from the analysis. This removed non-observation claims where the highest cost service was not typical for a claim associated with a major procedure.
Following these steps, a principal procedure representing the primary service driving the claim's overall utilization was identified for each remaining claim. For observation claims containing both G0379 and G0378 with a medical visit procedure, the principal procedure was identified as G0379 or G0378 depending on which code reports a higher line-item cost. Otherwise, observation claims were assigned a principal procedure of G0379 and G0378 depending on whether G0379 or G0378 with a medical visit procedure were respectively reported.
For non-observation claims, the principal procedure was identified as the claim's significant OPPS procedure code (status indicator of “S” or “T”) with the highest line-item cost. Non-observation claims where the earliest service date of the principal procedure occurred more than 5 days before or on the same date as the claim-through-date were removed from the analysis, as these were assumed to represent recurring services. Additionally, non-observation claims were trimmed to those where the principal procedure occurs on only a single service date, thus removing any claim that contains major recurring services and ensuring that the stay is initiated with a single instance of the major procedure.
To remove aberrant claims, each claim's non-observation total claim cost was then calculated by summing the line-item costs for all coded services and all OPPS packaged revenue centers on the claim. Each claim's span of coverage was also calculated as the number of days between the provision of the principal service and the claim's through-date. The geometric mean cost was calculated for each observation or non-observation principal procedure using the claims' total cost, and those claims with unreasonable costs (That is, claim costs above 100 times or below 1 percent of the principal procedure geometric mean cost) were trimmed from the analysis.
For purposes of the 2 midnight analysis, we then further subset the data to APCs having a status indicator of “T” in order remove services which were not relevant for the 2 midnight analysis that is, to remove those services that were more likely to represent diagnostic services or minor procedures interjected into a series of recurring services, and were less likely to trigger a “surgical” episode in which a continuous stay followed the procedure. For similar reasons, our medical officers also removed some of the remaining APCs based on clinical judgment that those services were unlikely to be indicative of a continuous protracted hospital stay. The full list of OPPS status indicators and their definitions is published in the OPPS/ASC proposed and final rules each year, available on our Web site at
As described in section II.D of this notice, we have also been performing an analysis of the claims experience since the implementation of the 2-midnight policy. This analysis has used claims data from the OPPS Limited Data Set. We have also been examining similar data from our Integrated Data Repository (see
We seek comment on the appropriate outpatient data source to use for the −0.2 percent estimate and any data trims and claims selection criteria that we should apply to the data.
This Appendix provides additional detail on how we identified inpatient stays spanning less than 2 midnights for surgical MS-DRGs for purposes of estimating the shift in inpatient cases.
The inpatient data used in the original −0.2 estimate was based on data from the CMS Integrated Data Repository (IDR) (see
When we now compare the number of inpatient stays less than 2 midnights for surgical MS-DRGs (excluding deaths and transfers) from the FY 2011 IDR data available to us at the time of the original −0.2 estimate (claims processed through June of 2013) to the number from the FY 2011 MedPAR data (claims processed through March of 2013), we get
In determining the 380,000 number from the FY 2011 MedPAR, the following inpatient claim selection criteria and data trims were applied to the data. We selected FY 2011 MedPAR claims based on a FY 2011 date of discharge where the National Claims History (NCH) claim type code was equal to “60” (inpatient hospital), the third position of the provider number group was equal to “0” (short-term hospital), the first 2 positions of the provider number were not equal to “21” (excludes Maryland hospitals), the destination discharge code was not equal to “30” (excludes still a patient), the special unit code was blank (excludes, for example, PPS exempt units), the GHO paid code was not equal to “1” (a group health organization has not paid the provider), the total charge amount was greater than 0, and the IME amount was not equal to the DRG price amount (indicating it was not a managed care claim).
As described in section II.D of this notice, we have also been performing an analysis of the claims experience since the implementation of the 2-midnight policy. This analysis has used data from the publicly available MedPAR file and the IDR.
We seek comment on the appropriate inpatient data source to use for the −0.2 percent estimate and any data trims and claims selection criteria that we should apply to the data.
B3 includes an impact evaluation and a process study. The impact evaluation will involve randomly assigning individuals to a treatment or comparison condition and comparing key outcomes. In addition, the study will collect information on employment, criminal justice and child support outcomes from administrative records. These data will be used to estimate the effects of the parenting or employment intervention on a range of outcomes including employment; earnings; child support; father/child contact, shared activities, and relationship quality; father's commitment to his child, parenting skills, and parenting efficacy; co-parenting relationship quality; and criminal justice outcomes.
The process study will describe and document each newly established intervention and how it operated to provide insight into the treatment differentials and the context for interpreting findings of the impact study. The process study will also highlight lessons to the field including what it takes to engage participants, the challenges sites face when implementing the parenting or employment intervention, and the participants' perspectives on whether the program components offered met their needs.
Data collection instruments for the B3 study include the following: (1) Screening for program eligibility to help ensure that only eligible fathers enroll in the study.
(2) nFORM management information system (MIS) to record study and participation information. Note: Only B3-specific burden is included with this request. All Responsible Fatherhood Grantees (funded by the ACF Office of Family Assistance) are required to use nFORM. nFORM is being developed by the Fatherhood and Marriage Local Evaluation and Cross-site (FaMLE Cross-site) Project and burden for these sites are captured under OMB #0970-0460. (3) Applicant characteristics and program operations data for one non-grantee site. We expect most of the B3 sites will be federally funded Responsible Fatherhood grantees, but it is possible that one site will not and therefore, this request includes burden for one site to use nFORM. (4) Baseline and follow-up surveys for the impact study. There will be two versions of each survey, specific to the intervention tested. (5) Baseline and follow-up questionnaires, interviews, focus groups, and surveys to inform the process study; these will also be specific to the intervention tested.
The sites that are part of the B3 study will use a slightly modified version of nFORM that includes B-3 specific information, such as: (1) B3-specific enrollment data (2) B3-specific information about focal child and co-parent in in sites testing a parenting intervention, and (3) B3 tracking of child and co-parent attendance in services with the father for program group members in sites testing a parenting intervention.
RESPONDENTS: Fathers seeking services from one of the six Responsible Fatherhood Programs in the B3 study and staff members working at the B3 sites.
In compliance with the requirements of Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Administration for Children and Families is soliciting public comment on the specific aspects of the information collection described above. Copies of the proposed collection of information can be obtained and comments may be forwarded by writing to the Administration for Children and Families, Office of Planning, Research and Evaluation, 330 C Street SW., Washington, DC 20201, Attn: OPRE Reports Clearance Officer. Email address:
The Department specifically requests comments on (a) whether the proposed 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 proposed collection of information; (c) the quality, utility, and clarity of the information to be collected; and (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. Consideration will be given to comments and suggestions submitted within 60 days of this publication.
Food and Drug Administration, HHS.
Notice of availability.
The Food and Drug Administration (FDA or Agency) is announcing the availability of a draft guidance for industry #233 entitled “Veterinary Feed Directive Common Format Questions and Answers.” On June 3, 2015, FDA published a final rule that revised the Agency's veterinary feed directive (VFD) regulations. During the rulemaking process, FDA received a few comments requesting that we require a uniform VFD form. Although we declined this request because we think that requiring a specific VFD form would be too prescriptive, we acknowledge that a common VFD format would help clients, veterinarians, and distributors (including feed mills) quickly identify relevant information on the VFD and are issuing this draft guidance to recommend a common VFD format.
Although you can comment on any guidance at any time (see 21 CFR 10.115(g)(5)), to ensure that the Agency considers your comment on this draft guidance before it begins work on the final version of the guidance, submit either electronic or written comments on the draft guidance by February 1, 2016.
You may submit comments as follows:
Submit electronic comments in the following way:
• Federal eRulemaking Portal:
• If you want to submit a comment with confidential information that you do not wish to be made available to the public, submit the comment as a written/paper submission and in the manner detailed (see “Written/Paper Submissions” and “Instructions”).
Submit written/paper submissions as follows:
• Mail/Hand delivery/Courier (for written/paper submissions): Division of Dockets Management (HFA-305), Food and Drug Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.
• For written/paper comments submitted to the Division of Dockets Management, FDA will post your comment, as well as any attachments, except for information submitted, marked and identified, as confidential, if submitted as detailed in “Instructions.”
• Confidential Submissions—To submit a comment with confidential information that you do not wish to be made publicly available, submit your comments only as a written/paper submission. You should submit two copies total. One copy will include the information you claim to be confidential with a heading or cover note that states “THIS DOCUMENT CONTAINS CONFIDENTIAL INFORMATION.” The Agency will review this copy, including the claimed confidential information, in its consideration of comments. The second copy, which will have the claimed confidential information redacted/blacked out, will be available for public viewing and posted on
Submit written requests for single copies of the draft guidance to the Policy and Regulations Staff (HFV-6), Center for Veterinary Medicine, Food and Drug Administration, 7519 Standish Pl., Rockville, MD 20855. Send one self-addressed adhesive label to assist that office in processing your requests. See the
Dragan Momcilovic, Center for Veterinary Medicine (HFV-226), Food and Drug Administration, 7519 Standish Pl., Rockville, MD 20855, 240-402-5944,
FDA is announcing the availability of a draft guidance for industry #233 entitled “Veterinary Feed Directive Common Format Questions and Answers.”
In 1996, Congress enacted the Animal Drug Availability Act (ADAA) to facilitate the approval and marketing of new animal drugs and medicated feeds. In passing the ADAA, Congress created a new regulatory category for certain animal drugs used in or on animal feed called VFD drugs. VFD drugs are new animal drugs intended for use in or on animal feed which are limited to use under the professional supervision of a licensed veterinarian. FDA published final regulations at § 558.6 (21 CFR 558.6) implementing the VFD-related provisions of the ADAA in 2000. On June 3, 2015 (80 FR 31707), FDA published a VFD final rule that revised those VFD regulations and introduced clarifying changes to specified definitions.
During the latest rulemaking process, FDA received a few comments requesting the Agency to require a uniform VFD format. We declined this request because we thought that requiring a specific format would be too prescriptive. However, we acknowledge that a common VFD format would help clients, veterinarians, and distributors (including feed mills) quickly identify relevant information on the VFD.
We are issuing this draft guidance to recommend a common VFD format. In the draft guidance, we use the term “VFD” to refer to the form used to convey the VFD order. This draft guidance describes the requirements in § 514.1(b)(9) (21 CFR 514.1(b)(9)) for sponsor submission of a VFD to FDA as part of the application process for approval of a new animal drug for use in or on animal feed as a VFD drug, as well as the required and optional information to be included on the VFD. This draft guidance provides examples that illustrate how a common VFD format might appear and how some of the information on the VFD may be prepopulated by a sponsor.
This level 1 draft guidance is being issued consistent with FDA's good guidance practices regulation (21 CFR 10.115). The draft guidance, when finalized, will represent the current thinking of FDA on “Veterinary Feed Directive Common Format Questions and Answers.” It does not establish any rights for any person and is not binding on FDA or the public. You can use an alternative approach if it satisfies the requirements of the applicable statutes and regulations.
This draft guidance refers to previously approved collections of information found in FDA regulations. These collections of information are subject to review by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520). The collections of information in § 514.1 have been approved under OMB control number 0910-0032. The collections of information in § 558.6 have been approved under OMB control number 0910-0363.
Persons with access to the Internet may obtain the draft guidance at either
In compliance with the requirement of Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, for opportunity for public comment on proposed data collection projects, the Office of the Director, the National Institutes of Health (NIH) will publish periodic summaries of proposed projects to be submitted to the Office of Management and Budget (OMB) for review and approval.
Written comments and/or suggestions from the public and affected agencies are invited to address one or more of the following points: (1) Whether the proposed collection of information is necessary for the proper performance of the function 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
Under the GDS Policy, all investigators who receive NIH funding to conduct large-scale genomic research are expected to register studies with human genomic data in dbGaP, no matter which NIH-designated data repository will maintain the data. As part of the registration process, investigators must provide basic study information such as the type of data that will be submitted to dbGaP, a description of the study, and an institutional assurance (
Investigators interested in using controlled-access data for secondary research must apply through dbGaP and be granted permission from the relevant NIH Data Access Committee(s). As part of the application process, investigators and their institutions must provide information such as a description of the proposed research use of controlled-access datasets that conforms to any data use limitations, agree to the Genomic Data User Code of Conduct, and agree to the terms of access through a Data Use Certification agreement. Requests to renew data access and reports to close out data use are similar to the initial data access request, requiring sign-off by both the requestor and the institution, but also ask for information about how the data have been used, and about publications, presentations, or intellectual property based on the research conducted with the accessed data as well as any data security issues or other data management incidents.
The NIH has developed online forms, available through dbGaP, in an effort to reduce the burden for researchers and their institutional officials to complete the study registration, data submission, data access, and renewal and closeout processes.
OMB approval is requested for 3 years. There are no costs to respondents other than their time. The total estimated annualized burden hours are 2,505.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
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.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
Substance Abuse and Mental Health Services Administration, HHS.
Notice.
The Department of Health and Human Services (HHS) notifies federal agencies of the laboratories and Instrumented Initial Testing Facilities (IITF) currently certified to meet the standards of the Mandatory Guidelines for Federal Workplace Drug Testing Programs (Mandatory Guidelines). The Mandatory Guidelines were first published in the
A notice listing all currently HHS-certified laboratories and IITFs is published in the
If any laboratory or IITF has withdrawn from the HHS National Laboratory Certification Program (NLCP) during the past month, it will be listed at the end and will be omitted from the monthly listing thereafter.
This notice is also available on the Internet at
Giselle Hersh, Division of Workplace Programs, SAMHSA/CSAP, Room 7-1051, One Choke Cherry Road, Rockville, Maryland 20857; 240-276-2600 (voice), 240-276-2610 (fax).
The Mandatory Guidelines were initially developed in accordance with Executive Order 12564 and section 503 of Pub. L. 100-71. The “Mandatory Guidelines for Federal Workplace Drug Testing Programs,” as amended in the revisions listed above, requires strict standards that laboratories and IITFs must meet in order to conduct drug and specimen
To become certified, an applicant laboratory or IITF must undergo three rounds of performance testing plus an on-site inspection. To maintain that certification, a laboratory or IITF must participate in a quarterly performance testing program plus undergo periodic, on-site inspections.
Laboratories and IITFs in the applicant stage of certification are not to be considered as meeting the minimum requirements described in the HHS Mandatory Guidelines. A HHS-certified laboratory or IITF must have its letter of certification from HHS/SAMHSA (formerly: HHS/NIDA), which attests that it has met minimum standards.
In accordance with the Mandatory Guidelines dated November 25, 2008 (73 FR 71858), the following HHS-certified laboratories and IITFs meet the minimum standards to conduct drug and specimen validity tests on urine specimens:
*The Standards Council of Canada (SCC) voted to end its Laboratory Accreditation Program for Substance Abuse (LAPSA) effective May 12, 1998. Laboratories certified through that program were accredited to conduct forensic urine drug testing as required by U.S. Department of Transportation (DOT) regulations. As of that date, the certification of those accredited Canadian laboratories will continue under DOT authority. The responsibility for conducting quarterly performance testing plus periodic on-site inspections of those LAPSA-accredited laboratories was transferred to the U.S. HHS, with the HHS' NLCP contractor continuing to have an active role in the performance testing and laboratory inspection processes. Other Canadian laboratories wishing to be considered for the NLCP may apply directly to the NLCP contractor just as U.S. laboratories do.
Upon finding a Canadian laboratory to be qualified, HHS will recommend that DOT certify the laboratory (
Federal Emergency Management Agency, DHS.
Notice.
This is a notice of the Presidential declaration of a major disaster for the State of Alaska (FEMA-4244-DR), dated October 30, 2015, and related determinations.
Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW., Washington, DC 20472, (202) 646-2833.
Notice is hereby given that, in a letter dated October 30, 2015, 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
I have determined that the damage in certain areas of the State of Alaska resulting from a severe storm on August 27, 2015, 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
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.
You are authorized to provide Public Assistance in the designated area 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 will be limited to 75 percent of the total eligible costs. Federal funds provided under the Stafford Act for Public Assistance also will be limited to 75 percent of the total eligible costs, with the exception of projects that meet the eligibility criteria for a higher Federal cost-sharing percentage under the Public Assistance Alternative Procedures Pilot Program for Debris Removal implemented pursuant to section 428 of the Stafford Act.
Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.
The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Thomas J. Dargan, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.
The following areas of the State of Alaska have been designated as adversely affected by this major disaster:
The North Slope Borough for Public Assistance.
All areas within the State of Alaska are eligible for assistance under the Hazard Mitigation Grant Program.
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.
Federal Emergency Management Agency, DHS.
Notice.
This notice amends the notice of a major disaster declaration for the State of South Carolina (FEMA-4241-DR), dated October 5, 2015, and related determinations.
Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW., Washington, DC 20472, (202) 646-2833.
The notice of a major disaster declaration for the State of South Carolina is hereby amended to include the following area among those areas determined to have been adversely affected by the event declared a major disaster by the President in his declaration of October 5, 2015.
Spartanburg County for Public Assistance (already designated for Individual Assistance).
Federal Emergency Management Agency, DHS.
Notice.
This notice amends the notice of a major disaster declaration for the State of California (FEMA-4240-DR), dated September 22, 2015, and related determinations.
Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW., Washington, DC 20472, (202) 646-2833.
Notice is hereby given that the incident period for this disaster is closed effective October 30, 2015.
Federal Emergency Management Agency, DHS.
Notice.
This notice amends the notice of a major disaster declaration for the State of Washington (FEMA-4242-DR), dated October 15, 2015, and related determinations.
Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW., Washington, DC 20472, (202) 646-2833.
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 October 15, 2015.
Clallam, Grays Harbor, and Whatcom Counties for Public Assistance.
Fish and Wildlife Service, Interior.
Notice; request for comments.
We (U.S. Fish and Wildlife Service) have sent an Information Collection Request (ICR) to OMB for review and approval. We summarize the ICR below and describe the nature of the collection and the estimated burden and cost. This information collection is scheduled to expire on December 31, 2015. We 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. However, under OMB regulations, we may continue to conduct or sponsor this information collection while it is pending at OMB.
You must submit comments on or before December 31, 2015.
Send your comments and suggestions on this information collection to the Desk Officer for the Department of the Interior at OMB-OIRA at (202) 395-5806 (fax) or
To request additional information about this ICR, contact Hope Grey at
• Assist livestock producers in undertaking proactive, nonlethal activities to reduce the risk of livestock loss due to predation by wolves; and
• Compensate livestock producers for livestock losses due to such predation.
The Act directs that the program be established as a grant program to provide funding to States and tribes, that the Federal cost share not exceed 50 percent, and that funds be expended equally between the two purposes. The Act included an authorization of appropriations up to $1 million each fiscal year for 5 years. The U.S. Fish and Wildlife Service Ecological Services Program will allocate the funding in the form of competitively awarded grants to States and tribes with a prior history of wolf depredation. States with delisted wolf populations are eligible for funding, provided that they meet the eligibility criteria contained in Pub. L. 111-11.
The following additional criteria apply to all WLDPGP grants and must be satisfied for a project to receive WLDPGP funding:
• Proposal cannot include U.S. Fish and Wildlife Service full-time equivalent (FTE) costs.
• Proposal cannot seek funding for projects that serve to satisfy regulatory requirements of the Endangered Species Act (ESA), including complying with a biological opinion under section 7 or fulfilling commitments of a habitat conservation plan (HCP) under ESA section 10, or for projects that serve to satisfy other Federal regulatory requirements (
• State administrative costs must be assumed by the State or included in the proposal in accordance with Federal requirements.
We will publish notices of funding opportunity on the Grants.gov Web site at
• Maintain files of all claims received under programs funded by the grant, including supporting documentation; and
• Submit an annual report that includes a summary of claims and expenditures under the program during the year and a description of any action taken on the claims.
On August 18, 2015, we published in the
We again invite comments concerning this information collection on:
• Whether or not the collection of information is necessary, including whether or not the information will have practical utility;
• The accuracy of our estimate of the burden for this collection of information;
• Ways to enhance the quality, utility, and clarity of the information to be collected; and
• Ways to minimize the burden of the collection of information on respondents.
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 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 OMB and us in your comment to withhold your personal identifying information from public review, we cannot guarantee that it will be done.
Interior.
Notice of availability; request for comments.
In accordance with the Oil Pollution Act of 1990 (OPA), the National Environmental Policy Act (NEPA), and the Framework Agreement for Early Restoration Addressing Injuries Resulting from the
• Via the Web:
• Via U.S. mail, you may request a CD of the Draft Phase V ERP/EA (see
• Via the Web:
• Via U.S. Mail: U.S. Fish and Wildlife Service, P.O. Box 49567, Atlanta, GA 30345.
Nanciann Regalado, at 404-679-4161.
On or about April 20, 2010, the mobile offshore drilling unit
Under the Oil Pollution Act 1990 (OPA; 33 U.S.C. 2701
The Trustees are:
• U.S. Department of the Interior (DOI), as represented by the National Park Service, U.S. Fish and Wildlife Service, and Bureau of Land Management;
• National Oceanic and Atmospheric Administration (NOAA), on behalf of the U.S. Department of Commerce;
• U.S. Department of Agriculture (USDA);
• U.S. Environmental Protection Agency (USEPA);
• State of Louisiana Coastal Protection and Restoration Authority, Oil Spill Coordinator's Office, Department of Environmental Quality, Department of Wildlife and Fisheries, and Department of Natural Resources;
• State of Mississippi Department of Environmental Quality;
• State of Alabama Department of Conservation and Natural Resources and Geological Survey of Alabama;
• State of Florida Department of Environmental Protection and Fish and Wildlife Conservation Commission; and
• For the State of Texas: Texas Parks and Wildlife Department, Texas General Land Office, and Texas Commission on Environmental Quality.
In the April 2011 Framework Agreement for Early Restoration Addressing Injuries Resulting from the
This Notice addresses Phase V of the early restoration process. In four previous phases, the Trustees selected, and BP agreed to fund, a total of 64 early restoration projects expected to cost a total of approximately $832 million. The Trustees selected these projects after public notice, public meetings, and consideration of public comments, through the Phase I Early Restoration Plan/Environmental Assessment (Phase I ERP/EA), Phase II Early Restoration Plan/Environmental Review (Phase II ERP/ER), the Programmatic and Phase III Early Restoration Plan and Early Restoration Programmatic Environmental Impact Statement (Phase III ERP/PEIS), and the Phase IV Early Restoration Plan/Environment Assessments (Phase IV ERP/EA).
The Trustees released the Phase I ERP/EA on April 20, 2012 (77 FR 23741) and the Phase II ERP/ER on February 5, 2013 (78 FR 8184). The Trustees released the Phase III ERP/PEIS on June 26, 2014 (79 FR 36328), and subsequently approved that Plan and programmatic EIS in a Record of Decision on October 31, 2014 (79 FR 64831). The Trustees released the Phase IV ERP/EA on September 23, 2015 (80 FR 57384). These plans are available at:
In the Draft Phase V Early Restoration Plan and Environmental Assessment announced in this Notice, the Trustees are proposing the first phase of the Florida Coastal Access Project to address lost recreational opportunities in Florida caused by the
The Draft Phase V ERP/EA is being released in accordance with the Oil Pollution Act (OPA), the Natural Resources Damage Assessment (NRDA) regulations found in the Code of Federal Regulations (CFR) at 15 CFR 990, the National Environmental Policy Act (42 U.S.C. 4321
The Trustees are considering the first phase of the Florida Coastal Access Project in the Draft Phase V ERP/EA. The total estimated cost for the proposed first phase of the Florida Coastal Access Project is $34,372,184. The total estimated cost of the proposed Florida Coastal Access Project is $45,415,573. The Trustees will propose in an additional future phase similar restoration activities that would utilize the remaining $11,043,389, if approved. Details on the proposed first phase of the Florida Coastal Access Project are provided in the Draft Phase V ERP/EA.
The proposed first phase of the Florida Coastal Access Project is intended to continue the process of using early restoration funding to restore natural resources, ecological services, and recreational use services injured or lost as a result of the
The Draft Phase V ERP/EA also includes notices of change and supporting analysis for two Phase III Early Restoration Projects: “Strategically Provided Boat Access Along Florida's Gulf Coast—City of Port St. Joe, Frank Pate Boat Ramp Improvements” and “Florida Artificial Reef Creation and Restoration.”
The Trustees have scheduled a public meeting to facilitate public review and comment on the Draft Phase V ERP/EA. Both written and verbal comments will be taken at the public meeting. The Trustees will hold an open house followed by a formal meeting. The public meeting will include a presentation of the Draft Phase V ERP/EA. After the public comment period ends, the Trustees will consider and address the comments received before issuing a final Phase V Early Restoration Plan and Environmental Assessment (Final Phase V ERP/EA). After issuing a Final Phase V ERP/EA and if the Trustees approve the first phase of the Florida Coastal Access Project, the Trustees will file a negotiated stipulation for the approved Florida Coastal Access Project with the court. If approved, the first phase of the Florida Coastal Access Project will then proceed to implementation, pending compliance with all applicable State and Federal laws. The Trustees anticipate considering a second phase of this Florida Coastal Access Project through a future restoration plan that will be subject to a separate notice and public comment process.
The Trustees seek public review and comment on the proposed first phase of the Florida Coastal Access Project and supporting analysis included in the Draft Phase V ERP/EA. Through this Notice of Availability, the Trustees are seeking public review and comment for only the Draft Phase V ERP/EA. 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. You may submit comments on the Draft Phase V ERP/EA by one of the methods described in
This public review and comment process for the Draft Phase V ERP/EA is separate from the public comment processes for the
The documents comprising the Administrative Record for the Draft Phase V ERP/EA can be viewed electronically at the following location:
The authority of this action is the Oil Pollution Act of 1990 (33 U.S.C. 2701
Bureau of Land Management, Interior.
Notice.
Pursuant to applicable provisions of the Federal Lands Recreation Enhancement Act (REA), the Monticello Field Office of the Bureau of Land Management (BLM) is proposing to begin collecting fees for overnight camping within four developed camping areas.
Effective six months after the publication of this notice, the BLM-Utah, Monticello Field Office would initiate fee collection at the Creek Pasture Campground, Creek Pasture Group Site, Superbowl Campground, and Indian Creek Falls Group Site for single occupancy campsites and group sites, unless the BLM publishes a
Don Hoffheins, Field Office Manager, BLM-Monticello Field Office, 365 N. Main, Monticello, UT 84535, (435) 587-1500. Persons who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 to leave a message or question for the above individual. The FIRS is available 24 hours a day, 7 days a week. Replies are provided during normal business hours.
The Utah Resource Advisory Council (RAC), functioning as a Recreation Resource Advisory Committee (RRAC), will review the proposal to charge fees at the four developed camping areas. Future adjustments in the fee amount will be made in accordance with the Monticello Field Office's publicly-reviewed recreation fee business plan covering the developed camping areas. Fee adjustments will be made after consultation with the Utah RRAC and general public support for the proposed fees are documented in conformance with section 6803(c) of the REA.
The four developed camping areas discussed in this notice are:
Under Section 6802(g)(2) of the REA, the camping areas listed above qualify as sites wherein visitors can be charged an “Expanded Amenity Recreation Fee.” Visitors wishing to use the expanded amenities the BLM has developed at the Creek Pasture Campground, Creek Pasture Group Site, Superbowl Campground, and Indian Creek Falls Group Site would purchase a Recreation Use Permit as described at 43 CFR part 2933. Pursuant to REA and implementing regulations at 43 CFR part 2933, fees may be charged for overnight camping and group use reservations where specific amenities and services are provided. Specific visitor fees will be identified and posted at the developed recreation sites. Fees for individual sites at Creek Pasture and Superbowl campgrounds must be paid at the self-service pay station located at the camping areas. Fees for the Creek Pasture and Indian Creek Falls group sites must be paid for in advance with the Monticello Field Office. People holding the “America the Beautiful—The National Parks and Federal Recreational Lands Senior Pass” or “Access Pass” would be entitled to a 50 percent discount on expanded amenity fees, except those associated with group reservations. Fees charged for use of the group sites would include a non-refundable site reservation fee.
The Creek Pasture Campground is located in the heavily-used Utah Highway 211 corridor along Indian Creek and has proven to be very popular. Its sites are in use throughout the majority of the tourist season. BLM has added amenities for resource protection and visitor enjoyment. Creek Pasture is within the Indian Creek Special Recreation Management Area (SRMA). The Creek Pasture Campground offers 3 toilets, 32 individual sites, an access road, regular patrols, fire rings, tent spaces, and picnic tables.
The Creek Pasture Group Site is located at the north end of the Creek Pasture Campground, within the Indian Creek SRMA. The Creek Pasture Group Site offers a toilet, an access road, regular patrols, fire rings, tent spaces, a shade shelter, and picnic tables.
The Superbowl Campground is located a quarter mile from Highway 211 within the Indian Creek SRMA and offers two toilets, seventeen individual sites, an improved access road, regular patrols, fire rings, tent spaces, and picnic tables.
The Indian Creek Falls Group Site is located approximately two miles from Highway 211 within the Indian Creek SRMA and offers a toilet, an access road, regular patrols, fire rings, tent spaces, and picnic tables.
The BLM is committed to providing and receiving fair market value for the use of developed recreation facilities and services in a manner that meets public use demands, provides quality experiences, and protects important resources. The BLM's policy is to collect fees at all specialized recreation sites, or where the BLM provides facilities, equipment or services at Federal expense, in connection with outdoor use as authorized by the REA. In an effort to meet increasing demands for services and increased maintenance of developed facilities, the BLM would implement a fee program for the developed camping areas. The BLM's mission for the developed camping areas is to ensure that funding is available to maintain facilities and recreational opportunities, to provide for law enforcement presence, and to protect public health and safety and public land resources. This mission entails communication with those who will be most directly affected by the developed camping areas such as recreationists, other recreation providers, partners, neighbors, elected officials, and other agencies.
Camping and group use fees would be consistent with other established fee sites in the area including other BLM-administered sites and those managed by the United States Forest Service, National Park Service, and Utah State Parks and Recreation. Future adjustments in the fee amount will be made following the Monticello Field Office's recreation fee business plan covering the sites, in consultation with the Utah RRAC and other public stakeholders prior to a fee adjustment.
In December 2004, the REA was signed into law. The REA provides authority for the Secretaries of the Interior and Agriculture to establish, modify, charge, and collect recreation fees for use of some Federal recreational lands and waters, and contains specific provisions addressing public involvement in the establishment of recreation fees, including a requirement that RRACs or Councils have the
16 U.S.C. 6803(b).
United States International Trade Commission.
Notice.
The Commission hereby gives notice that it has instituted a review pursuant to the Tariff Act of 1930 (“the Act”), as amended, to determine whether revocation of the antidumping duty order on petroleum wax candles from China would be likely to lead to continuation or recurrence of material injury. Pursuant to the Act, interested parties are requested to respond to this notice by submitting the information specified below to the Commission;
Mary Messer (202-205-3193), 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 (
(1)
(2) The
(3) The
(4) The
(5) An
Former Commission employees who are seeking to appear in Commission five-year reviews are advised that they may appear in a review even if they participated personally and substantially in the corresponding underlying original investigation or an earlier review of the same underlying investigation. The Commission's designated agency ethics official has advised that a five-year review is not the same particular matter as the underlying original investigation, and a five-year review is not the same particular matter as an earlier review of the same underlying investigation for purposes of 18 U.S.C. 207, the post employment statute for Federal employees, and Commission rule 201.15(b) (19 CFR 201.15(b)), 79 FR 3246 (Jan. 17, 2014), 73 FR 24609 (May 5, 2008). Consequently, former employees are not required to seek Commission approval to appear in a review under Commission rule 19 CFR 201.15, even if the corresponding underlying original investigation or an earlier review of the same underlying investigation was pending when they were Commission employees. For further ethics advice on this matter, contact Carol McCue Verratti, Deputy Agency Ethics Official, at 202-205-3088.
(1) The name and address of your firm or entity (including World Wide Web address) and name, telephone number, fax number, and email address of the certifying official.
(2) A statement indicating whether your firm/entity is a U.S. producer of the
(3) A statement indicating whether your firm/entity is willing to participate in this proceeding by providing information requested by the Commission.
(4) A statement of the likely effects of the revocation of the antidumping duty order on the
(5) A list of all known and currently operating U.S. producers of the
(6) A list of all known and currently operating U.S. importers of the
(7) A list of 3-5 leading purchasers in the U.S. market for the
(8) A list of known sources of information on national or regional prices for the
(9) If you are a U.S. producer of the
(a) Production (quantity) and, if known, an estimate of the percentage of total U.S. production of the
(b) Capacity (quantity) of your firm to produce the
(c) the quantity and value of U.S. commercial shipments of the
(d) the quantity and value of U.S. internal consumption/company transfers of the
(e) the value of (i) net sales, (ii) cost of goods sold (COGS), (iii) gross profit, (iv) selling, general and administrative (SG&A) expenses, and (v) operating income of the
(10) If you are a U.S. importer or a trade/business association of U.S. importers of the
(a) The quantity and value (landed, duty-paid but not including antidumping or countervailing duties) of U.S. imports and, if known, an estimate of the percentage of total U.S. imports of
(b) the quantity and value (f.o.b. U.S. port, including antidumping and/or countervailing duties) of U.S. commercial shipments of
(c) the quantity and value (f.o.b. U.S. port, including antidumping and/or countervailing duties) of U.S. internal consumption/company transfers of
(11) If you are a producer, an exporter, or a trade/business association of producers or exporters of the
(a) Production (quantity) and, if known, an estimate of the percentage of total production of
(b) Capacity (quantity) of your firm(s) to produce the
(c) the quantity and value of your firm's(s') exports to the United States of
(12) Identify significant changes, if any, in the supply and demand conditions or business cycle for the
(13) (Optional) A statement of whether you agree with the above definitions of the
This proceeding is being conducted under authority of Title VII of the Tariff Act of 1930; this notice is published pursuant to section 207.61 of the Commission's rules.
By order of the Commission.
United States International Trade Commission.
Notice.
The Commission hereby gives notice of the schedule for issuance of a consistency determination following receipt on November 6, 2015, of a request from the United States Trade Representative (USTR) for a determination under section 129(a)(4) of the URAA that would render the Commission's action in connection with its countervailing duty investigation regarding imports of hot-rolled steel products from India, in Inv. No. 701-
Douglas E. Corkran (202-205-3057), Office of Investigations, or Robin L. Turner (202-205-3103), Office of the General Counsel, 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 (
For further information concerning the conduct of this proceeding and rules of general application, consult the Commission's Rules of Practice and Procedure, part 201, subparts A through E (19 CFR part 201), and part 207, subparts A and C (19 CFR part 207).
Additional written submissions to the Commission, including requests pursuant to section 201.12 of the Commission's rules, will not be accepted unless good cause is shown for accepting such submissions, or unless the submission is pursuant to a specific request by a Commissioner or Commission staff.
In accordance with sections 201.16(c) and 207.3 of the Commission's rules, each document filed by a party to this proceeding must be served on all other parties to this proceeding (as identified by either the public or BPI service list), and a certificate of service must be timely filed. The Secretary will not
This proceeding is being conducted under authority of title VII of the Tariff Act of 1930 and section 129 of the URAA.
By order of the Commission.
Judicial Conference of the United States, Committee on Rules of Practice and Procedure.
Notice of open meeting.
The Committee on Rules of Practice and Procedure will hold a two-day meeting. The meeting will be open to public observation but not participation. An agenda and supporting materials will be posted at least 7 days in advance of the meeting at:
January 7-8, 2016.
Royal Palms Hotel, 5200 East Camelback Road, Phoenix, Arizona 85018.
Rebecca A. Womeldorf, Rules Committee Secretary, Rules Committee Support Office, Administrative Office of the United States Courts, Washington, DC 20544, telephone (202) 502-1820.
On November 24, 2015, the Department of Justice lodged a proposed Consent Decree with the United States District Court for the Northern District of Illinois in the lawsuit entitled
The consent decree settles claims against the owner and manager of 52 housing units in 50 separate properties located in or near Rockford, Illinois. The claims were brought on behalf of the Environmental Protection Agency and the Department of Housing and Urban Development under the Residential Lead-Based Paint Hazard Reduction Act, 42 U.S.C. 4851
Under the Consent Decree, the Defendant will certify that he is complying with residential lead paint notification requirements. The Defendant will submit a plan for window replacement work and will replace all windows known to or believed to contain lead-based paint in these 52 housing units owned or managed by Defendant that are not certified lead-based paint free. In addition, Defendant will abate lead-based paint hazards on friction and impact surfaces, stabilize other lead-based paint hazards, and pay an administrative penalty of $5,000.
The publication of this notice opens a period for public comment on the proposed Consent Decree. Comments should be addressed to the Assistant Attorney General, Environment and Natural Resources Division, and should refer to
During the public comment period, the proposed Consent Decree may be examined and downloaded at this Justice Department Web site:
Please enclose a check or money order for $14.00 (25 cents per page reproduction cost) payable to the United States Treasury.
Notice.
On November 30, 2015, the Department of Labor (DOL) will submit the Occupational Safety and Health Administration (OSHA) sponsored information collection request (ICR) titled, “Asbestos in Shipyards Standard,” to the Office of Management and Budget (OMB) for review and approval for continued use, without change, in accordance with the Paperwork Reduction Act of 1995 (PRA), 44 U.S.C. 3501
The OMB will consider all written comments that agency receives on or before December 31, 2015.
A copy of this ICR with applicable supporting documentation; including a description of the likely respondents, proposed frequency of response, and estimated total burden may be obtained free of charge from the RegInfo.gov Web site at
Submit comments about this request by mail or courier to the Office of Information and Regulatory Affairs, Attn: OMB Desk Officer for DOL-OSHA, Office of Management and Budget, Room 10235, 725 17th Street NW., Washington, DC 20503; by Fax: 202-395-5806 (this is not a toll-free number); or by email:
Contact Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or by email at
44 U.S.C. 3507(a)(1)(D).
This ICR seeks to extend PRA authority for the Asbestos in Shipyards Standard information collection requirements codified in regulations 29 CFR 1915.1001 that help to protect workers from the adverse health effects that may result from occupational exposure to asbestos. The major information collection requirements in the standard include: implementing an exposure-monitoring program that informs workers of their exposure-monitoring results; ensuring notification of on-site employers, at multi-employer worksites, when establishing regulated areas for work performed with asbestos-containing materials (ACMs) and/or presumed asbestos-containing materials (PACMs), of the requirements for such regulated areas, and the measures necessary to protect workers from overexposure; providing medical surveillance for workers potentially exposed to ACMs and/or PACMs, including administering a worker medical questionnaire, providing information to the examining physician, and providing the physician's written opinion to the worker; and maintaining records of objective data used for exposure determinations, worker exposure monitoring and medical surveillance records, training records, the record (
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 it is approved by the OMB under the PRA 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 Control Number.
OMB authorization for an ICR cannot be for more than three (3) years without renewal, and the current approval for this collection is scheduled to expire on November 30, 2015. The DOL seeks to extend PRA authorization for this information collection for three (3) more years, without any change to existing requirements. The DOL notes that existing information collection requirements submitted to the OMB receive a month-to-month extension while they undergo review. For additional substantive information about this ICR, see the related notice published in the
Interested parties are encouraged to send comments to the OMB, Office of Information and Regulatory Affairs at the address shown in the
• Evaluate 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;
• Evaluate 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;
• Enhance the quality, utility, and clarity of the information to be collected; and
• 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,
Notice.
The Department of Labor, as part of its continuing effort to reduce paperwork and respondent burden, conducts a pre-clearance consultation program to provide the general public and Federal agencies with an opportunity to comment on proposed and/or continuing collections of information in accordance with the Paperwork Reduction Act of 1995 (PRA95) [44 U.S.C. 3506(c)(2)(A)]. This program helps to ensure that requested data can be provided in the desired format, reporting burden (time and financial resources) is minimized, collection instruments are clearly understood, and the impact of collection requirements on respondents can be properly assessed. The Bureau of Labor Statistics (BLS) is soliciting comments concerning the proposed revision of the “The Consumer Expenditure Surveys: The Quarterly Interview and the Diary.” A copy of the proposed information collection request (ICR) can be obtained by contacting the individual listed below in the
Written comments must be submitted to the office listed in the Addresses section of this notice on or before February 1, 2016.
Send comments to Nora Kincaid, BLS Clearance Officer, Division of Management Systems, Bureau of Labor Statistics, Room 4080, 2 Massachusetts Avenue NE., Washington, DC 20212. Written comments also may be transmitted by fax to 202-691-5111 (this is not a toll free number).
Nora Kincaid, BLS Clearance Officer, at 202-691-7628 (this is not a toll free number). (See
The Consumer Expenditure (CE) Surveys collect data on consumer
The data from the CE Surveys are used (1) for CPI revisions, (2) to provide a continuous flow of data on income and expenditure patterns for use in economic analysis and policy formulation, and (3) to provide a flexible consumer survey vehicle that is available for use by other Federal Government agencies. Public and private users of price statistics, including Congress and the economic policymaking agencies of the Executive branch, rely on data collected in the CPI in their day-to-day activities. Hence, data users and policymakers widely accept the need to improve the process used for revising the CPI. If the CE Surveys were not conducted on a continuing basis, current information necessary for more timely, as well as more accurate, updating of the CPI would not be available. In addition, data would not be available to respond to the continuing demand from the public and private sectors for current information on consumer spending.
In the Quarterly Interview Survey, each consumer unit (CU) in the sample is interviewed every three months over four calendar quarters. The sample for each quarter is divided into three panels, with CUs being interviewed every three months in the same panel of every quarter. The Quarterly Interview Survey is designed to collect data on the types of expenditures that respondents can be expected to recall for a period of three months or longer. In general the expenses reported in the Interview Survey are either relatively large, such as property, automobiles, or major appliances, or are expenses which occur on a fairly regular basis, such as rent, utility bills, or insurance premiums.
The Diary (or recordkeeping) Survey is completed at home by the respondent family for two consecutive one-week periods. The primary objective of the Diary Survey is to obtain expenditure data on small, frequently purchased items which normally are difficult to recall over longer periods of time.
Office of Management and Budget clearance is being sought for the proposed revision of the Consumer Expenditure Surveys: The Quarterly Interview and the Diary.
Additionally, as part of an ongoing effort to improve data quality, maintain or increase response rates, and reduce data collection costs, CE is seeking clearance to field an Incentives/Outlets Field Test. CE plans to test the effect different incentive delivery procedures and incentive amounts have on survey costs, response rates, and data quality for the CE Interview Survey (CEQ). The results of this FY2016 Incentives Field test will be used to inform the Large Scale Feasibility test (to be fielded in 2018) as well as the overall Gemini Redesign project. Also, CE and the Consumer Price Index (CPI) plan to test integrating outlet questions into the CEQ survey. Outlet data are currently collected by the Telephone Point of Purchase Survey (TPOPS). The results of the integration of outlet questions into the CEQ survey will be used to inform future CPI initiatives.
A full list of the proposed changes to the Quarterly Interview Survey and Diary Survey are available upon request.
In addition to the Incentives/Outlets test, the Consumer Expenditure program is planning several tests over the next several years in an effort to improve the CE surveys in the areas of both data quality and respondent burden.
The Bureau of Labor Statistics is particularly interested in comments that:
• Evaluate 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.
• Evaluate 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.
• Enhance the quality, utility, and clarity of the information to be collected.
• 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,
Comments submitted in response to this notice will be summarized and/or included in the request for Office of Management and Budget approval of the information collection request; they also will become a matter of public record.
National Archives and Records Administration (NARA).
Notice of availability of proposed records schedules; request for comments.
The National Archives and Records Administration (NARA) publishes notice at least once monthly of certain Federal agency requests for records disposition authority (records schedules). Once approved by NARA, records schedules provide agencies with mandatory instructions for what to do with records when agencies no longer need them for current Government business. The instructions authorize agencies to preserve records of continuing value in the National Archives of the United States and to destroy, after a specified period, records lacking administrative, legal, research, or other value. NARA publishes notice in the
NARA must receive requests for copies in writing by December 31, 2015. Once NARA appraises the records, we will send you a copy of the schedule you requested. We usually prepare appraisal memoranda that contain additional information concerning the records covered by a proposed schedule. You may also request these. If you do, we will also provide them once we have completed the appraisal. You have 30 days after we send you these requested documents in which to submit comments.
You may request a copy of any records schedule identified in this notice by contacting Records Management Services (ACNR) using one of the following means:
You must cite the control number, which appears in parentheses after the name of the agency which submitted the schedule, and a mailing address. If you would like an appraisal report, please include that in your request.
Margaret Hawkins, Director, by mail at Records Management Services (ACNR); National Archives and Records Administration; 8601 Adelphi Road; College Park, MD 20740-6001, by phone at 301-837-1799, or by email at
Each year, Federal agencies create billions of records on paper, film, magnetic tape, and other media. To control this accumulation, agency records managers prepare schedules proposing retention periods for records and submit these schedules for NARA's approval. These schedules provide for timely transfer into the National Archives of historically valuable records and authorize disposal of all other records after the agency no longer needs them to conduct its business. Some schedules are comprehensive and cover all the records of an agency or one of its major subdivisions. Most schedules, however, cover records of only one office or program or a few series of records. Many of these update previously approved schedules, and some include records proposed as permanent.
The schedules listed in this notice are media-neutral unless otherwise specified. An item in a schedule is media-neutral when an agency may apply the disposition instructions to records regardless of the medium in which it has created or maintains the records. Items included in schedules submitted to NARA on or after December 17, 2007, are media-neutral unless the item is specifically limited to a specific medium. (See 36 CFR 1225.12(e).)
Agencies may not destroy Federal records without the approval of the Archivist of the United States. The Archivist grants this approval only after thorough consideration of the records' administrative use by the agency of origin, the rights of the Government and of private people directly affected by the Government's activities, and whether or not the records have historical or other value.
In addition to identifying the Federal agencies and any subdivisions requesting disposition authority, lists the organizational unit(s) accumulating the records or lists that the schedule has agency-wide applicability (in the case of schedules that cover records that may be accumulated throughout an agency); provides the control number assigned to each schedule, the total number of schedule items, and the number of temporary items (the records proposed for destruction); and includes a brief description of the temporary records. The records schedule itself contains a full description of the records at the file unit level as well as their disposition. If NARA staff has prepared an appraisal memorandum for the schedule, it also includes information about the records. You may request additional information about the disposition process at the addresses above.
1. Department of Agriculture, Forest Service (DAA-0095-2016-0001, 6 items, 1 temporary item). Duplicate copies of aerial photographic imagery. Proposed for permanent retention are original analog negative film, digital imagery that does not exist in analog format, negative imagery indices, and film reports.
2. Department of Education, Federal Student Aid (DAA-0441-2015-0001, 1 item, 1 temporary item). Master file of an electronic information system containing account information about recipients of Federal Student Aid.
3. Department of the Interior, Agency-wide (DAA-0048-2013-0008, 15 items, 4 temporary items). Policy development records relating to legislative input, compliance reporting, and rulemaking. Proposed for permanent retention are high-level policy records to include oversight, official legislative reports, public affairs, regulations, executive commissions, and media records.
4. Department of State, Bureau of Conflict and Stabilization Operations (DAA-0059-2014-0025, 4 items, 4 temporary items). Records of the Office of Learning and Training, including training materials, guidance and best practice documents, evaluations, and administration records.
5. Department of State, Bureau of Energy Resources (DAA-0059-2015-0011, 8 items, 8 temporary items). Records include press guidance, publicity materials, copies of analysis and briefing materials, and public comments related to energy issues.
6. Department of State, Bureau of European and Eurasian Affairs and International Organizations (DAA-0059-2015-0014, 1 item, 1 temporary item). Master file of an electronic information system used to track employee performance evaluations.
7. Department of Transportation, Federal Highway Administration (DAA-0406-2014-0003, 3 items, 3 temporary items). Records concerning a data portal used to access traffic data.
8. Department of Transportation, Federal Highway Administration (DAA-0406-2015-0002, 1 item, 1 temporary item). Records relating to emergency relief program case files, including applications, fund allocation, correspondence, and reports.
9. Department of Transportation, Surface Transportation Board (DAA-0134-2013-0013, 1 item, 1 temporary item). Electronic records relating to Amtrak on-time performance.
10. Department of the Treasury, Internal Revenue Service (DAA-0058-2015-0007, 1 item, 1 temporary item).
11. Federal Communications Commission, Office of the Managing Director (DAA-0173-2015-0006, 3 items, 3 temporary items). Records include worksheets and information collected from service providers related to the Telecommunications Relay Service.
12. Federal Communications Commission, Wireline Competition Bureau (DAA-0173-2015-0008, 1 item, 1 temporary item). Annual certification letters for telecommunications carriers.
13. National Archives and Records Administration, Research Services (N2-60-14-1, 1 item, 1 temporary item). Records of the Department of Justice, Civil Division, relating to the Mortgage and Lien Foreclosure Act. The records consist of temporary case files for civil actions against a holder of a defaulted mortgage or loan (1931-1948). These records were accessioned to the National Archives but lack sufficient historical value to warrant continued preservation.
14. National Archives and Records Administration, Research Services (N2-60-14-2, 1 item, 1 temporary item). Records of the Department of Justice, Civil and Criminal Divisions, relating to the Federal Housing Act. The records consist of temporary case files for civil and criminal actions regarding insured mortgages and home improvement and repair loans (1934-1968). These records were accessioned to the National Archives but lack sufficient historical value to warrant continued preservation.
15. National Archives and Records Administration, Research Services (N2-60-14-3, 1 item, 1 temporary item). Department of Justice, Environment and Natural Resources Division, temporary case files for civil and criminal actions regarding eviction and delinquent rentals owed to U.S. Government owned housing programs (1938-1949). These records were accessioned to the National Archives but lack sufficient historical value to warrant continued preservation.
16. National Archives and Records Administration, Research Services (N2-60-14-4, 1 item, 1 temporary item). Department of Justice, Civil and Criminal Divisions, temporary case files for civil and criminal actions relating to the collection of farm security, rural rehabilitation and soil conservation loans made by the Farmers Home Administration (1938-1949). These records were accessioned to the National Archives but lack sufficient historical value to warrant continued preservation.
17. National Archives and Records Administration, Research Services (N2-60-14-5, 1 item, 1 temporary item). Department of Justice, Civil and Criminal Divisions, temporary case files for civil and criminal actions relating to the collection of unpaid loans made by the Farm Credit Administration (1934-1949). These records were accessioned to the National Archives but lack sufficient historical value to warrant continued preservation.
18. National Archives and Records Administration, Research Services (N2-60-14-6, 1 item, 1 temporary item). Department of Justice, Criminal Division, temporary case files for criminal actions relating to the theft of U.S. Government property (1921-1957). These records were accessioned to the National Archives but lack sufficient historical value to warrant continued preservation.
19. National Archives and Records Administration, Research Services (N2-60-14-7, 1 item, 1 temporary item). Department of Justice, Civil and Criminal Divisions, temporary case files for civil and criminal actions relating to claims filed under the War Risk Insurance Act (1917-1948). These records were accessioned to the National Archives but lack sufficient historical value to warrant continued preservation.
20. National Archives and Records Administration, Research Services (N2-60-14-8, 1 item, 1 temporary item). Department of Justice, Criminal Division, temporary case files for criminal actions relating to individual impersonation or misrepresentation as Federal officers, agents, employees, and members of the U.S. Armed Forces (1921-1951). These records were accessioned to the National Archives but lack sufficient historical value to warrant continued preservation.
Postal Regulatory Commission.
Notice.
The Commission is noticing a recent Postal Service filing concerning the addition of Priority Mail Contract 154 to the competitive product list. This notice informs the public of the filing, invites public comment, and takes other administrative steps.
Submit comments electronically via the Commission's Filing Online system at
David A. Trissell, General Counsel, at 202-789-6820.
In accordance with 39 U.S.C. 3642 and 39 CFR 3020.30
The Postal Service contemporaneously filed a redacted contract related to the proposed new product under 39 U.S.C. 3632(b)(3) and 39 CFR 3015.5. Request, Attachment B.
To support its Request, the Postal Service filed a copy of the contract, a copy of the Governors' Decision authorizing the product, proposed changes to the Mail Classification Schedule, a Statement of Supporting Justification, a certification of compliance with 39 U.S.C. 3633(a), and an application for non-public treatment of certain materials. It also filed supporting financial workpapers.
The Commission establishes Docket Nos. MC2016-18 and CP2016-24 to consider the Request pertaining to the proposed Priority Mail Contract 154 product and the related contract, respectively.
The Commission invites comments on whether the Postal Service's filings in the captioned dockets are consistent with the policies of 39 U.S.C. 3632, 3633, or 3642, 39 CFR part 3015, and 39 CFR part 3020, subpart B. Comments are
The Commission appoints James F. Callow to serve as Public Representative in these dockets.
1. The Commission establishes Docket Nos. MC2016-18 and CP2016-24 to consider the matters raised in each docket.
2. Pursuant to 39 U.S.C. 505, James F. Callow is appointed to serve as an officer of the Commission to represent the interests of the general public in these proceedings (Public Representative).
3. Comments are due no later than December 3, 2015.
4. The Secretary shall arrange for publication of this order in the
By the Commission.
Postal Regulatory Commission.
Notice.
The Commission is noticing a recent Postal Service filing concerning the addition of Priority Mail Express, Priority Mail, & First-Class Package Service Contract 6 to the competitive product list. This notice informs the public of the filing, invites public comment, and takes other administrative steps.
Submit comments electronically via the Commission's Filing Online system at
David A. Trissell, General Counsel, at 202-789-6820.
In accordance with 39 U.S.C. 3642 and 39 CFR 3020.30
The Postal Service contemporaneously filed a redacted contract related to the proposed new product under 39 U.S.C. 3632(b)(3) and 39 CFR 3015.5. Request, Attachment B.
To support its Request, the Postal Service filed a copy of the contract, a copy of the Governors' Decision authorizing the product, proposed changes to the Mail Classification Schedule, a Statement of Supporting Justification, a certification of compliance with 39 U.S.C. 3633(a), and an application for non-public treatment of certain materials. It also filed supporting financial workpapers.
The Commission establishes Docket Nos. MC2016-21 and CP2016-27 to consider the Request pertaining to the proposed Priority Mail Express, Priority Mail, & First-Class Package Service Contract 6 product and the related contract, respectively.
The Commission invites comments on whether the Postal Service's filings in the captioned dockets are consistent with the policies of 39 U.S.C. 3632, 3633, or 3642, 39 CFR part 3015, and 39 CFR part 3020, subpart B. Comments are due no later than December 3, 2015. The public portions of these filings can be accessed via the Commission's Web site (
The Commission appoints Katalin K. Clendenin to serve as Public Representative in these dockets.
It is ordered:
1. The Commission establishes Docket Nos. MC2016-21 and CP2016-27 to consider the matters raised in each docket.
2. Pursuant to 39 U.S.C. 505, Katalin K. Clendenin is appointed to serve as an officer of the Commission to represent the interests of the general public in these proceedings (Public Representative).
3. Comments are due no later than December 3, 2015.
4. The Secretary shall arrange for publication of this order in the
By the Commission.
Postal Service
Notice.
The Postal Service gives notice of filing a request with the Postal Regulatory Commission to add a domestic shipping services contract to the list of Negotiated Service Agreements in the Mail Classification Schedule's Competitive Products List.
Elizabeth A. Reed, 202-268-3179.
The United States Postal Service® hereby gives notice that, pursuant to 39 U.S.C. 3642 and 3632(b)(3), on November 24, 2015, it filed with the Postal Regulatory Commission a
Postal Service
Notice.
The Postal Service gives notice of filing a request with the Postal Regulatory Commission to add a domestic shipping services contract to the list of Negotiated Service Agreements in the Mail Classification Schedule's Competitive Products List.
Elizabeth A. Reed, 202-268-3179.
The United States Postal Service® hereby
Postal Service
Notice.
The Postal Service gives notice of filing a request with the Postal Regulatory Commission to add a domestic shipping services contract to the list of Negotiated Service Agreements in the Mail Classification Schedule's Competitive Products List.
Elizabeth A. Reed, 202-268-3179.
The United States Postal Service® hereby gives notice that, pursuant to 39 U.S.C. 3642 and 3632(b)(3), on November 24, 2015, it filed with the Postal Regulatory Commission a
Postal Service
Notice.
The Postal Service gives notice of filing a request with the Postal Regulatory Commission to add a domestic shipping services contract to the list of Negotiated Service Agreements in the Mail Classification Schedule's Competitive Products List.
Elizabeth A. Reed, 202-268-3179.
The United States Postal Service® hereby gives notice that, pursuant to 39 U.S.C. 3642 and 3632(b)(3), on November 24, 2015, it filed with the Postal Regulatory Commission a
Under Section 2(d) of the Railroad Retirement Act (RRA), monthly survivor annuities are payable to surviving widow(er)s, parents, unmarried children, and in certain cases, divorced spouses, mothers (fathers), remarried widow(er)s, and grandchildren of deceased railroad employees if there are no qualified survivors of the employee immediately eligible for an annuity. The requirements relating to the annuities are prescribed in 20 CFR 216, 217, 218, and 219.
To collect the information needed to help determine an applicant's entitlement to, and the amount of, a survivor annuity the RRB uses Forms AA-17,
The on-line automated survivor annuity application (Forms AA-17, AA-18, AA-19, and AA-20) process obtains information about an applicant's marital history, work history, benefits from other government agencies, and Medicare entitlement for a survivor annuity. An RRB representative interviews the applicant either at a field office (preferred), an itinerant point, or by telephone. During the interview, the RRB representative enters the information obtained into an on-line information system. Upon completion of the interview, the system generates, for the applicant's review, either Form AA-17cert or AA-17sum, which provides a summary of the information that the applicant provided or verified. Form AA-17cert,
The RRB proposes to remove the paper version of Forms AA-17, AA-18, AA-19, and AA-20 from the information collection due to receiving less than 10 responses a year. No changes are proposed to electronic Forms AA-17cert, AA-17sum, or manual Forms AA-17b and AA-19a.
Section 2(c) of the Railroad Retirement Act (RRA), provides for the payment of annuities to spouses of railroad retirement annuitants who meet the requirements under the RRA. The age requirements for a spouse annuity depend on the employee's age, date of retirement, and years of railroad service. The requirements relating to the annuities are prescribed in 20 CFR 216, 218, 219, 232, 234, and 295.
To collect the information needed to help determine an applicant's entitlement to, and the amount of, a spouse annuity the RRB uses Form AA-3,
The AA-3 application process gathers information from an applicant about their marital history, work history, benefits from other government agencies, and Medicare entitlement for a spouse annuity. An RRB representative interviews the applicant either at a field office (preferred), an itinerant point, or by telephone. During the interview, the RRB representative enters the information obtained into an on-line information system. Upon completion of the interview, the system generates, for the applicant's review, either Form AA-3cert or AA-3sum, which is a summary of the information that the applicant provided or verified. Form AA-3cert,
The RRB proposes to remove the paper version of the AA-3 from the information collection due to receiving less than 10 responses a year.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the
The Exchange is proposing to adopt Exchange Rule 11.27 to implement the Regulation NMS Plan to Implement a Tick Size Pilot Program (“Plan”).
The text of the proposed rule change is available at the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in Sections A, B, and C below, of the most significant parts of such statements.
On August 25, 2014, NYSE Group, Inc., on behalf of BATS Exchange, Inc., BATS Y-Exchange, Inc., Chicago Stock Exchange, Inc., EDGA Exchange, Inc., EDGX Exchange, Inc., Financial Industry Regulatory Authority, Inc. (“FINRA”), NASDAQ OMX BX, Inc., NASDAQ OMX PHLX LLC, the Nasdaq Stock Market LLC, New York Stock Exchange LLC (“NYSE”), NYSE MKT LLC, and NYSE Arca, Inc. (collectively “Participants”), filed with the Commission, pursuant to Section 11A of the Act
The Plan is designed to allow the Commission, market participants, and the public to study and assess the impact of increment conventions on the liquidity and trading of the common stocks of small-capitalization companies. Each Participant is required to comply, and to enforce compliance by its member organizations, as applicable, with the provisions of the Plan. As is described more fully below, the proposed rules would require Members
The Pilot will include stocks of companies with $3 billion or less in market capitalization, an average daily trading volume of one million shares or less, and a volume weighted average price of at least $2.00 for every trading day. The Pilot will consist of a control group of approximately 1400 Pilot Securities and three test groups with 400 Pilot Securities in each (selected by a stratified random sampling process).
In approving the Plan, the Commission noted that the Trading Center data reporting requirements would facilitate an analysis of the effects of the Pilot on liquidity (
The Plan contains requirements for collecting and transmitting data to the Commission and to the public.
Appendix B.II of the Plan (Market and Marketable Limit Order Data) requires Trading Centers to submit information relating to market orders and marketable limit orders, including the time of order receipt, order type, the order size, the National Best Bid and National Best Offer (“NBBO”) quoted price, the NBBO quoted depth, the average execution price-share-weighted average, and the average execution time-share-weighted average.
The Plan requires Appendix B.I and B.II data to be submitted by Participants that operate a Trading Center, and by members of the Participants that operate Trading Centers. The Plan provides that each Participant that is the Designated Examining Authority (“DEA”) for a member of the Participant that operates a Trading Center shall collect such data in a pipe delimited format, beginning six months prior to the Pilot Period and ending six months after the end of the Pilot Period. The Plan also requires the Participant, operating as DEA, to transmit this information to the SEC within 30 calendar days following month end.
The Exchange is therefore proposing Rule 11.27(b) to set forth the requirements for the collection and transmission of data pursuant to Appendix B.I and B.II of the Plan. Proposed Rule 11.27(b)(1) requires that a Member that operates a Trading Center shall establish, maintain and enforce written policies and procedures that are reasonably designed to comply with the data collection and transmission requirements of Items I and II to Appendix B of the Plan, and a Member that is a Market Maker shall establish, maintain and enforce written policies and procedures that are reasonably designed to comply with the data collection and transmission requirements of Item IV of Appendix B of the Plan and Item I of Appendix C of the Plan.
Rule 11.27(b)(2) provides that the Exchange shall collect and transmit to the SEC the data described in Items I and II of Appendix B of the Plan relating to trading activity in Pre-Pilot Securities and Pilot Securities on a Trading Center operated by the Exchange. The Exchange shall transmit such data to the SEC in a pipe delimited format, on a disaggregated basis by Trading Center, within 30 calendar days following month end for: (i) Each Pre-Pilot Data Collection Security for the period beginning six months prior to the Pilot Period through the trading day immediately preceding the Pilot Period; and (ii) each Pilot Security for the period beginning on the first day of the Pilot Period through six months after the end of the Pilot Period. The Exchange also shall make such data publicly available on the Exchange Web site on a monthly basis at no charge and will not identify the Member that generated the data.
Appendix B.IV (Daily Market Maker Participation Statistics) requires a Participant to collect data related to Market Maker participation from each Market Maker
Proposed Rule 11.27(b)(3)(B) provides that the Exchange shall transmit the data collected by the DEA pursuant to Rule 11.27(b)(3)(A) above relating to Market Maker activity on a Trading Center operated by the Exchange to the SEC in a pipe delimited format within 30 calendar days following month end. The Exchange shall also make such data publicly available on the Exchange Web site on a monthly basis at no charge and shall not identify the Trading Center that generated the data.
Appendix C.I (Market Maker Profitability) requires a Participant to collect data related to Market Maker profitability from each Market Maker for which it is the DEA. Specifically, the Participant is required to collect the total number of shares of orders executed by the Market Maker; the raw Market Maker realized trading profits, and the raw Market Maker unrealized trading profits. Data shall be collected for dates starting six months prior to the Pilot Period through six months after the end of the Pilot Period. This data shall be collected on a monthly basis, to be provided in a pipe delimited format to the Participant, as DEA, within 30 calendar days following month end. Appendix C.II (Aggregated Market Maker Profitability) requires the Participant, as DEA, to aggregate the Appendix C.I data, and to categorize this data by security as well as by the control group and each Test Group. That aggregated data shall contain information relating to total raw Market Maker realized trading profits, volume-weighted average of raw Market Maker realized trading profits, the total raw Market Maker unrealized trading profits, and the volume-weighted average of Market Maker unrealized trading profits.
The Exchange is therefore proposing Rule 11.27(b)(4) to set forth the requirements for the collection and transmission of data pursuant to Appendix C.I of the Plan. Proposed Rule 11.27(b)(4)(A) requires that a Member that is a Market Maker shall collect and transmit to their DEA the data described in Item I of Appendix C of the Plan, as modified by Paragraph (b)(5) with respect to executions in Pilot Securities that have settled or reached settlement date that were executed on any Trading Center. The proposed rule also requires Members to provide such data in a format required by their DEA by 12 p.m. EST on T+4 for executions during and
The Exchange is also adopting a rule setting forth the manner in which Market Maker participation will be calculated. Item III of Appendix B of the Plan requires each Participant that is a national securities exchange to collect daily Market Maker registration statistics categorized by security, including the following information: (i) Ticker symbol; (ii) the Participant exchange; (iii) number of registered market makers; and (iv) the number of other registered liquidity providers. Therefore, the Exchange proposes to adopt Rule 11.27(b)(5) providing that the Exchange shall collect and transmit to the SEC the data described in Item III of Appendix B of the Plan relating to daily Market Maker registration statistics in a pipe delimited format within 30 calendar days following month end for: (i) For transactions in each Pre-Pilot Data Collection Security for the period beginning six months prior to the Pilot Period through the trading day immediately preceding the Pilot Period; and (ii) For transactions in each Pilot Security for the period beginning on the first day of the Pilot Period through six months after the end of the Pilot Period.
The Exchange is also proposing, through Interpretations and Policies, to clarify other aspects of the data collection requirements.
Interpretations and Policy .03 requires that Members populate a field to identify to their DEA whether an order is affected by the bands in place pursuant to the National Market System Plan to Address Extraordinary Market Volatility.
The Exchange and the other Participants have determined that it is appropriate to create a new flag for reporting orders that are affected by the Limit-Up Limit-Down bands. Accordingly, a Trading Center shall report a value of “Y” to their DEA when the ability of an order to execute has been affected by the Limit-Up Limit-Down bands in effect at the time of order receipt. A Trading Center shall report a value of “N” to their DEA when the ability of an order to execute has not been affected by the Limit-Up Limit-Down bands in effect at the time of order receipt.
Interpretation and Policy .03 also requires, for dually-listed securities, that the Participant indicate whether the order was handled domestically, or routed to a foreign venue. Accordingly, the Participant will indicate, for purposes of Appendix B.I, whether the order was: (1) Fully executed domestically, or (2) fully or partially executed on a foreign market. For purposes of Appendix B.II, the Participant will classify all orders in dually-listed Pilot and Pre-Pilot Securities as: (1) Directed to a domestic venue for execution; (2) may only be directed to a foreign venue for execution; or (3) was fully or partially directed to a foreign venue at the discretion of the Member. The Exchange believes that this proposed flag will better identify orders in dually-listed securities, as such orders that were executed in foreign venues would not be subject to the Plan's quoting and trading requirements, and could otherwise compromise the integrity of the data.
Interpretations and Policy .04 relates to the time ranges specified in Appendix B.I.a(14), B.I.a(15), B.I.a(21) and B.I.a(22).
Interpretations and Policy .05 relates to the relevant measurement for purposes of Appendix B.I.a(31)-(33) reporting. Currently, the Plan states that this data shall be reported as of the time of order execution. The Exchange and the other Participants believe that this information should more properly be captured at the time of order receipt as evaluating share-weighted average prices at the time of order receipt is more consistent with the goal of observing the effect of the Pilot on the liquidity of Pilot Securities. The Exchange is therefore proposing to make this change through Interpretations and Policy .05.
Interpretations and Policy .06 addresses the status of not-held and auction orders for purposes of Appendix B.I reporting. Currently, Appendix B.I sets forth eight categories of orders, including market orders, marketable limit orders, and inside-the-quote resting limit orders, for which daily market quality statistics must be reported. Currently, Appendix B.I does not provide a category for not held orders, clean cross orders, auction orders, or orders received when the NBBO is crossed. The Exchange and the other Participants have determined that it is appropriate to include separate categories for both not held orders and auction orders for purposes of Appendix B reporting. The Exchange is therefore proposing Interpretations and Policy .06 to provide that not held orders shall be included as an order type for purposes of Appendix B reporting, and shall be assigned the number (18). Clean cross orders shall be included as an order type for purposes of Appendix B reporting, and shall be assigned the number (19); auction orders shall be included an as order type for purposes of Appendix B reporting, and shall be assigned the number (20); and orders that cannot otherwise be classified, including, for example, orders received when the NBBO is crossed shall be included as an order type for purposes of Appendix B reporting, and shall be assigned the number (21). All of these orders already are included in the scope of Appendix B; however, without this proposed change, these order types would be categorized with other orders, such as regular held orders, that should be able to be fully executed upon receipt, which would compromise the value of this data.
The Exchange is proposing Interpretations and Policy .07 to clarify the scope of the Plan as it relates to Members that only execute orders limited purposes. Specifically, The Exchange and the other Participants believe that a Member that only executes orders otherwise than on a national securities exchange for the purpose of: (1) Correcting a bona fide error related to the execution of a customer order; (2) purchasing a security from a customer at a nominal price solely for purposes of liquidating the customer's position; or (3) completing the fractional share portion of an order
The Exchange is proposing Interpretations and Policy .08 to clarify that, for purposes of the Plan, Trading Centers must begin the data collection required pursuant to Appendix B.I.a(1) through B.II.(y) of the Plan and Item I of Appendix C of the Plan on April 4, 2016. While the Exchange or the Member's DEA will provide the information required by Appendix B and C of the Plan during the Pilot Period, the requirement that the Exchange or their DEA provide information to the SEC within 30 days following month end and make such data publicly available on its Web site pursuant to Appendix B and C shall commence six months prior to the beginning of the Pilot Period.
The Exchange is proposing Interpretations and Policy .09 to address the requirement in Appendix C.I(b) of the Plan that the calculation of raw Market Maker realized trading profits utilize a last in, first out (“LIFO”)-like method to determine which share prices shall be used in that calculation. The Exchange and the other Participants believe that it is more appropriate to utilize a methodology that yields LIFO-like results, rather than utilizing a LIFO-like method, and the Exchange is therefore proposing Interpretations and Policy .09 to make this change.
Finally, the Exchange is proposing Interpretations and Policy .10 to address the securities that will be used for data collection purposes prior to the commencement of the Pilot. The Exchange and the other Participants have determined that it is appropriate to collect data for a group of securities that is larger, and using different quantitative thresholds, than the group of securities that will be Pilot Securities. The Exchange is therefore proposing Interpretations and Policy .09 to define “Pre-Pilot Data Collection Securities” as the securities designated by the Participants for purposes of the data collection requirements described in Items I, II and IV of Appendix B and Item I of Appendix C of the Plan for the period beginning six months prior to the Pilot Period and ending on the trading
The proposed rule change will be effective upon Commission approval. The implementation date will be April 4, 2016.
The Exchange believes that its proposal is consistent with Section 6(b) of the Act
The Exchange believes that this proposal is consistent with the Act because it implements and clarifies the provisions of the Plan, and is designed to assist the Exchange in meeting its regulatory obligations pursuant of the Plan. In approving the Plan, the SEC noted that the Pilot was an appropriate, data-driven test that was designed to evaluate the impact of a wider tick size on trading, liquidity, and the market quality of securities of smaller capitalization companies, and was therefore in furtherance of the purposes of the Act. The Exchange believes that this proposal is in furtherance of the objectives of the Plan, as identified by the SEC, and is therefore consistent with the Act because the proposal implements and clarifies the requirements of the Plan and applies specific obligations to Members in furtherance of compliance with the Plan.
The Exchange does not believe that the proposed rule change will result in any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The Exchange notes that the proposed rule change implements the provisions of the Plan, and is designed to assist the Exchange in meeting its regulatory obligations pursuant of the Plan. The Exchange also notes that the data collection requirements for Members that operate Trading Centers will apply equally to all such Members, as will the data collection requirements for Market Makers.
Written comments were neither solicited nor received.
Within 45 days of the date of publication of this notice in the
Interested persons are invited to submit written data, views and arguments concerning the foregoing, including whether the proposal is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange proposes to add Managed Fund Shares to the list of securities eligible to be Qualified Securities under the Lead Market Maker Program of Rule 7014(f). The Exchange will implement the proposed change no earlier than December 1, 2015 and no later than January 4, 2016. The implementation date will be announced by an Equity Trader Alert.
The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The Exchange is proposing to include Managed Fund Shares, as described under Rule 5735, to the list of securities eligible to be treated as a Qualified Security under the Lead Market Maker (“LMM”) Program of Rule 7014(f). The LMM Program is designed to provide incentive to market makers to make markets in certain relatively illiquid exchange-traded products (“ETPs”). The Exchange provides credits to a designated LMM for execution of a Qualified Security. Under Rule 7014(f)(1), a Qualified Security is defined as an exchange-traded fund or index-linked security listed on Nasdaq pursuant to Nasdaq Rules 5705 (Exchange Traded Funds: Portfolio Depository Receipts and Index Fund Shares), 5710 (Securities Linked to the Performance of Indexes and Commodities, Including Currencies), or 5720 (Trust Issued Receipts), and it must have at least one LMM. A LMM is a registered Nasdaq market maker for a Qualified Security that has committed to maintain minimum performance standards. A LMM is selected by Nasdaq based on factors including, but not limited to, experience with making markets in exchange-traded funds and index-linked securities, adequacy of capital, willingness to promote Nasdaq as a marketplace, issuer preference, operational capacity, support personnel, and history of adherence to Nasdaq rules and securities laws. Nasdaq may limit the number of LMMs in a security, or modify a previously established limit, upon prior written notice to members.
As noted above, Nasdaq currently includes in the program Portfolio Depository Receipts, Index Fund Shares, Securities Liked to the Performance of Indexes and Commodities, and Trust Issued Receipts. Nasdaq is proposing to add another ETP, Managed Fund Shares, as eligible to be a Qualified Security under the LMM Program. A Managed Fund Share is a security that (a) represents an interest in a registered investment company (“Investment Company”) organized as an open-end management investment company or similar entity, that invests in a portfolio of securities selected by the Investment Company's investment adviser consistent with the Investment Company's investment objectives and policies; (b) is issued in a specified aggregate minimum number in return for a deposit of a specified portfolio of securities and/or a cash amount with a value equal to the next determined net asset value; and (c) when aggregated in the same specified minimum number, may be redeemed at a holder's request, which holder will be paid a specified portfolio of securities and/or cash with a value equal to the next determined net asset value.
Nasdaq believes that the proposed rule change is consistent with the provisions of Section 6 of the Act,
The Exchange believes that inclusion of Managed Fund Shares in the LMM Program is reasonable because they are currently relatively thinly-traded on Nasdaq, and the LMM Program is
The Exchange does not believe that the proposed rule change will result in any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act, as amended. Specifically, the change is designed to promote improved market quality through the application of an ETP incentive program to a type of ETP that is currently not part of the program, and has comparatively low liquidity. Such a change is designed to improve market quality in Qualified Securities on Nasdaq, and does not place a burden on competition between market participants as the changes are applied consistently to all participants. Lastly, to the extent market quality improves on Nasdaq in Managed Fund Shares, the proposed change may promote competition among exchanges for new Managed Fund Share listings and similar incentive programs, to the benefit of all market participants transacting in Managed Fund Shares.
No written comments were either solicited or received.
Because the foregoing proposed rule change does not: (i) Significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, if consistent with the protection of investors and the public interest, the proposed rule change has become effective pursuant to Section 19(b)(3)(A) of the Act
At any time within 60 days of the filing of the proposed rule change, the Commission may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule change should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
All submissions should refer to File Number SR-NASDAQ-2015-145. 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 Web site (
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Exchange proposes to establish fees for the NYSE MKT Integrated Feed. The proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of those statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant parts of such statements.
The Exchange proposes to establish the fees for the NYSE MKT Integrated Feed in the NYSE MKT Equities Proprietary Market Data Fee Schedule (“Fee Schedule”).
1.
2.
3.
Under the proposal, for Non-Display Use of NYSE MKT Integrated Feed, there would be three categories of, and fees applicable to, data recipients. One, two or three categories of Non-Display Use may apply to a data recipient.
• Under the proposal, the Category 1 Fee would be $5,000 per month and would apply when a data recipient's Non-Display Use of the NYSE MKT Integrated Feed is on its own behalf, not on behalf of its clients.
• Under the proposal, Category 2 Fees would be $5,000 per month and would apply to a data recipient's Non-Display Use of the NYSE MKT Integrated Feed on behalf of its clients.
• Under the proposal, Category 3 Fees would be $5,000 and would apply to a data recipient's Non-Display Use of the NYSE MKT Integrated Feed for the purpose of internally matching buy and sell orders within an organization, including matching customer orders for data recipient's own behalf and/or on behalf of its clients. This category would apply to Non-Display Use in trading platforms, such as, but not restricted to, alternative trading systems (“ATSs”), broker crossing networks, broker crossing systems not filed as ATSs, dark pools, multilateral trading facilities, exchanges and systematic internalization systems. Category 3 Fees would be capped at $15,000 per month for each data recipient for the NYSE MKT Integrated Feed.
Non-Display Use fees for NYSE MKT Integrated Feed include, for customers also paying access fees for NYSE MKT BBO, NYSE MKT Trades, NYSE MKT OpenBook and NYSE MKT Order Imbalances, the Non-Display Use for such products when declared within the same category of use.
The description of the three non-display use categories is set forth in the Fee Schedule in endnote 1 and that endnote would be referenced in the NYSE MKT Integrated Feed fees on the Fee Schedule. The text in the endnote would remain unchanged.
Data recipients that receive the NYSE MKT Integrated Feed for Non-Display Use would be required to complete and submit a Non-Display Use Declaration before they would be authorized to receive the feed.
4.
In addition, if a data recipient's use of the NYSE MKT Integrated Feed data changes at any time after the data recipient submits a Non-Display Use Declaration, the data recipient must inform the Exchange of the change by completing and submitting at the time of the change an updated declaration reflecting the change of use.
5.
The Exchange notes that the three existing data feed products—NYSE MKT OpenBook, NYSE MKT Trades, and NYSE MKT Order Imbalances—would continue to be available to vendors and subscribers separately, in each case at the same prices at which they are currently available.
The Exchange believes that the proposed rule change is consistent with the provisions of Section 6 of the Act,
The Exchange believes it is equitable and not unfairly discriminatory to make the NYSE MKT Integrated Feed available free of charge through December 31, 2015 because providing it at no charge would provide an opportunity for vendors and subscribers to determine whether the NYSE MKT Integrated Feed suits their needs without incurring fees. Other exchanges provide or have provided market data products free for a certain period of time.
The fees for the NYSE MKT Integrated Feed are reasonable because they represent not only the value of the data available from three existing data feeds but also the value of receiving the data on an integrated basis. Receiving the data on an integrated basis provides greater efficiencies and reduced errors for vendors and subscribers that currently choose to integrate the data themselves after receiving it from the Exchange. Some vendors and subscribers may not have the technology or resources to integrate the separate data feeds in a timely and/or efficient manner, and thus the integration feature of the product may be valuable to them.
Moreover, the fees are equitably allocated and not unfairly discriminatory because vendors and subscribers may choose to continue to receive some or all of the data through the existing separate feeds at current prices, or they can choose to pay for the NYSE MKT Integrated Feed in order to received integrated data, or they can choose a combination of the two approaches, thereby allowing each vendor or subscriber to choose the best business solution for itself.
The Exchange believes the proposed monthly Access Fee of $2,500 and monthly Redistribution Fee of $1,500 for NYSE MKT Integrated Feed are reasonable because they are comparable to the total of the same types of fees for NYSE MKT OpenBook, NYSE MKT Trades, and NYSE MKT Order Imbalances. The monthly Access Fee for NYSE MKT OpenBook is $1,000, for NYSE MKT Trades is $750 and for NYSE MKT Order Imbalances is $500.
The Exchange believes that it is reasonable to charge redistribution fees because vendors receive value from redistributing the data in their business products for their customers. The redistribution fees also are equitable and not unfairly discriminatory because they will be charged on an equal basis to those vendors that choose to redistribute the data. Also, the proposed redistribution fee for NYSE MKT Integrated Feed is reasonable because it is comparable to the redistribution fees that are currently charged by other exchanges.
The proposed monthly Professional User Fee (Per User) of $10 and Non-Professional User Fee (Per User) of $2 are reasonable because they are comparable to the total of the per user fees for NYSE MKT OpenBook and NYSE MKT Trades. The monthly Professional User Fee (Per User) for NYSE MKT OpenBook is $5 and for NYSE MKT Trades, it is $1. The monthly Non-Professional User Fee (Per User) for NYSE MKT OpenBook is $1 and for NYSE MKT Trades, it is $0.05.
The Exchange believes that having separate Professional and Non-Professional User fees for the NYSE MKT Integrated Feed is reasonable because it will make the product more affordable and result in greater availability to Professional and Non-Professional Users. Setting a modest Non-Professional User fee is reasonable because it provides an additional method for Non-Professional Users to access the NYSE MKT Integrated Feed by providing the same data that is available to Professional Users. The Exchange believes that the proposed fees are equitable and not unfairly discriminatory because they will be charged uniformly to recipient firms and Users. The fee structure of differentiated Professional and Non-Professional fees applies to the user fees applicable to NYSE MKT OpenBook and NYSE MKT Trades and has long been used by the Exchange in order to reduce the price of data to Non-Professional Users and make it more broadly available.
The Exchange believes the proposed Non-Display Use fees are reasonable, equitable and not unfairly discriminatory because they reflect the value of the data to the data recipients in their profit-generating activities and do not impose the burden of counting non-display devices. After gaining further experience with the non-display fee structure, the Exchange believes that the proposed Non-Display Use fees reflect the significant value of the non-display data to data recipients, which purchase such data on an entirely voluntary basis. Non-display data can be used by data recipients for a wide variety of profit-generating purposes, including proprietary and agency trading and smart order routing, as well as by data recipients that operate order matching and execution platforms that compete directly with the Exchange for order flow. The data also can be used for a variety of non-trading purposes that indirectly support trading, such as risk management and compliance. While some of these non-trading uses do not directly generate revenues, they can nonetheless substantially reduce the recipient's costs by automating such functions so that they can be carried out in a more efficient and accurate manner and reduce errors and labor costs, thereby benefiting end users. The Exchange believes that charging for non-trading uses is reasonable because data recipients can derive substantial value from such uses, for example, by automating tasks so that they can be performed more quickly and accurately and less expensively than if they were performed manually.
Data can be processed much faster by a non-display device than it can be by a human being processing information that he or she views on a data terminal. Non-display devices also can dispense data to multiple computer applications as compared with the restriction of data to one display terminal. While non-display data has become increasingly valuable to data recipients who can use it to generate substantial profits, it has become increasing difficult for them and the Exchange to accurately count non-display devices. The number and type of non-display devices, as well as their complexity and interconnectedness, have grown in recent years, creating administrative challenges for vendors, data recipients, and the Exchange to accurately count such devices and audit such counts. Unlike a display device, such as a Bloomberg terminal, it is not possible to simply walk through a trading floor or areas of a data recipient's premises to identify non-display devices. During an audit, an auditor must review a firm's entitlement report to determine usage. While display use is generally associated with an individual end user and/or unique user ID, a non-display use is more difficult to account for because the entitlement report may show a server name or Internet protocol (“IP”) address or it may not. The auditor must review each IP or server and further inquire about downstream use and quantity of servers with access to data; this type of counting is very labor-intensive and prone to inaccuracies.
Market data technology and usage has evolved to the point where it is no longer practical, nor fair and equitable, to simply count non-display devices. The administrative costs and difficulties of establishing reliable counts and conducting an effective audit of non-display devices have become too burdensome, impractical, and non-economic for the Exchange, vendors, and data recipients. Indeed, some data recipients dislike the burden of having to comply with count-based audit processes, and the Exchange's non-display pricing policies are a direct response to such complaints as well as a further competitive distinction between the Exchange and other markets. The Exchange believes that the proposed fee structure for non-display use is reasonable, equitable, and not unfairly discriminatory in light of these developments.
The Non-Display Use fees for the NYSE MKT Integrated Feed are reasonable because they represent the extra value of receiving the data for Non-Display Use on an integrated basis. The Exchange believes that the proposed fees directly and appropriately reflect the significant value of using NYSE MKT Integrated Feed on a non-display basis in a wide range of computer-automated functions relating to both trading and non-trading activities and that the number and range of these functions continue to grow through innovation and technology developments.
The Exchange believes that it is reasonable to require annual submissions of the Non-Display Use Declaration so that the Exchange will have current and accurate information about the use of the NYSE MKT Integrated Feed and can correctly assess fees for the uses of the NYSE MKT Integrated Feed. The annual submission requirement is equitable and not unfairly discriminatory because it will apply to all users.
The Exchange believes that it is reasonable to impose a late fee in connection with the submission of the Non-Display Use Declaration. In order to correctly assess fees for the non-display use of NYSE MKT Integrated Feed, the Exchange needs to have current and accurate information about the use of NYSE MKT Integrated Feed. The failure of data recipients to submit the Non-Display Use Declaration on time leads to potentially incorrect billing and administrative burdens, including tracking and obtaining late Non-Display Use Declarations and correcting and following up on payments owed in connection with late Non-Display Use Declarations. The purpose of the late fee is to incent data recipients to submit the Non-Display Use Declaration promptly to avoid the administrative burdens associated with the late submission of Non-Display Use Declarations. The Non-Display Declaration Late Fee is equitable and not unfairly discriminatory because it will apply to all data recipients that choose to subscribe to the NYSE MKT Integrated Feed.
In addition, the proposed fees are reasonable when compared to fees for comparable products, including the NYSE Arca Integrated Feed,
The fees are also equitable and not unfairly discriminatory because they will apply to all data recipients that choose to subscribe to the NYSE MKT Integrated Feed.
The Exchange also notes that the NYSE MKT Integrated Feed is entirely optional. The Exchange is not required to make the NYSE MKT Integrated Feed available or to offer any specific pricing alternatives to any customers, nor is any firm required to purchase the NYSE MKT Integrated Feed. Firms that purchase the NYSE MKT Integrated Feed would do so for the primary goals of using it to increase revenues, reduce expenses, and in some instances compete directly with the Exchange (including for order flow); those firms are able to determine for themselves whether the NYSE MKT Integrated Feed or any other similar products are attractively priced or not.
Firms that do not wish to purchase the NYSE MKT Integrated Feed at the new prices have a variety of alternative market data products from which to choose,
The decision of the United States Court of Appeals for the District of Columbia Circuit in
In fact, the legislative history indicates that the Congress intended that the market system `evolve through the interplay of competitive forces as unnecessary regulatory restrictions are removed' and that the SEC wield its regulatory power `in those situations where competition may not be sufficient,' such as in the creation of a `consolidated transactional reporting system.'
As explained below in the Exchange's Statement on Burden on Competition, the Exchange believes that there is substantial evidence of competition in the marketplace for proprietary market data and that the Commission can rely upon such evidence in concluding that the fees established in this filing are the product of competition and therefore satisfy the relevant statutory standards. In addition, the existence of alternatives to these data products, such as consolidated data and proprietary data from other sources, as described below, further ensures that the Exchange cannot set unreasonable fees, or fees that are unreasonably discriminatory, when vendors and subscribers can select such alternatives.
As the
For these reasons, the Exchange believes that the proposed fees are reasonable, equitable, and not unfairly discriminatory.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. An exchange's ability to price its proprietary market data feed products is constrained by actual competition for the sale of proprietary market data products, the joint product nature of exchange platforms, and the existence of alternatives to the Exchange's proprietary data.
The market for proprietary data products is currently competitive and inherently contestable because there is fierce competition for the inputs necessary for the creation of proprietary data and strict pricing discipline for the proprietary products themselves. Numerous exchanges compete with one another for listings and order flow and sales of market data itself, providing ample opportunities for entrepreneurs who wish to compete in any or all of those areas, including producing and distributing their own market data. Proprietary data products are produced and distributed by each individual exchange, as well as other entities, in a vigorously competitive market. Indeed, the U.S. Department of Justice (“DOJ”) (the primary antitrust regulator) has expressly acknowledged the aggressive actual competition among exchanges, including for the sale of proprietary market data. In 2011, the DOJ stated that exchanges “compete head to head to offer real-time equity data products. These data products include the best bid
Moreover, competitive markets for listings, order flow, executions, and transaction reports provide pricing discipline for the inputs of proprietary data products and therefore constrain markets from overpricing proprietary market data. Broker-dealers send their order flow and transaction reports to multiple venues, rather than providing them all to a single venue, which in turn reinforces this competitive constraint. As a 2010 Commission Concept Release noted, the “current market structure can be described as dispersed and complex” with “trading volume . . . dispersed among many highly automated trading centers that compete for order flow in the same stocks” and “trading centers offer[ing] a wide range of services that are designed to attract different types of market participants with varying trading needs.”
If an exchange succeeds in its competition for quotations, order flow, and trade executions, then it earns trading revenues and increases the value of its proprietary market data products because they will contain greater quote and trade information. Conversely, if an exchange is less successful in attracting quotes, order flow, and trade executions, then its market data products may be less desirable to customers using them in support of order routing and trading decisions in light of the diminished content; data products offered by competing venues may become correspondingly more attractive. Thus, competition for quotations, order flow, and trade executions puts significant pressure on an exchange to maintain both execution and data fees at reasonable levels.
In addition, in the case of products that are also redistributed through market data vendors, such as Bloomberg and Thompson Reuters, the vendors themselves provide additional price discipline for proprietary data products because they control the primary means of access to certain end users. These vendors impose price discipline based upon their business models. For example, vendors that assess a surcharge on data they sell are able to refuse to offer proprietary products that their end users do not or will not purchase in sufficient numbers. Vendors will not elect to make available NYSE MKT Integrated Feed unless their customers request it, and customers will not elect to pay the proposed fees unless NYSE MKT Integrated Feed can provide value by sufficiently increasing revenues or reducing costs in the customer's business in a manner that will offset the fees. All of these factors operate as constraints on pricing proprietary data products.
Transaction execution and proprietary data products are complementary in that market data is both an input and a byproduct of the execution service. In fact, proprietary market data and trade executions are a paradigmatic example of joint products with joint costs. The decision of whether and on which platform to post an order will depend on the attributes of the platforms where the order can be posted, including the execution fees, data availability and quality, and price and distribution of data products. Without a platform to post quotations, receive orders, and execute trades, exchange data products would not exist.
The costs of producing market data include not only the costs of the data distribution infrastructure, but also the costs of designing, maintaining, and operating the exchange's platform for posting quotes, accepting orders, and executing transactions and the cost of regulating the exchange to ensure its fair operation and maintain investor confidence. The total return that a trading platform earns reflects the revenues it receives from both products and the joint costs it incurs.
Moreover, an exchange's broker-dealer customers generally view the costs of transaction executions and market data as a unified cost of doing business with the exchange. A broker-dealer will only choose to direct orders to an exchange if the revenue from the transaction exceeds its cost, including the cost of any market data that the broker-dealer chooses to buy in support of its order routing and trading decisions. If the costs of the transaction are not offset by its value, then the broker-dealer may choose instead not to purchase the product and trade away from that exchange. There is substantial evidence of the strong correlation between order flow and market data purchases. For example, in April 2015, more than 80% of the transaction volume on each of NYSE MKT and NYSE MKT's affiliates NYSE Arca and New York Stock Exchange LLC (“NYSE”) was executed by market participants that purchased one or more proprietary market data products (the 20 firms were not the same for each market). A supra-competitive increase in the fees for either executions or market data would create a risk of reducing an exchange's revenues from both products.
Other market participants have noted that proprietary market data and trade executions are joint products of a joint platform and have common costs.
Analyzing the cost of market data product production and distribution in isolation from the cost of all of the inputs supporting the creation of market data and market data products will inevitably underestimate the cost of the data and data products because it is impossible to obtain the data inputs to create market data products without a fast, technologically robust, and well-regulated execution system, and system and regulatory costs affect the price of both obtaining the market data itself and creating and distributing market data products. It would be equally misleading, however, to attribute all of an exchange's costs to the market data portion of an exchange's joint products. Rather, all of an exchange's costs are incurred for the unified purposes of attracting order flow, executing and/or routing orders, and generating and selling data about market activity. The total return that an exchange earns reflects the revenues it receives from the joint products and the total costs of the joint products.
As noted above, the level of competition and contestability in the market is evident in the numerous alternative venues that compete for order flow, including 11 equities self-regulatory organization (“SRO”) markets, as well as various forms of ATSs, including dark pools and electronic communication networks (“ECNs”), and internalizing broker-dealers. SRO markets compete to attract order flow and produce transaction reports via trade executions, and two FINRA-regulated Trade Reporting Facilities compete to attract transaction reports from the non-SRO venues.
Competition among trading platforms can be expected to constrain the aggregate return that each platform earns from the sale of its joint products, but different trading platforms may choose from a range of possible, and equally reasonable, pricing strategies as the means of recovering total costs. For example, some platforms may choose to pay rebates to attract orders, charge relatively low prices for market data products (or provide market data products free of charge), and charge relatively high prices for accessing posted liquidity. Other platforms may choose a strategy of paying lower rebates (or no rebates) to attract orders, setting relatively high prices for market data products, and setting relatively low prices for accessing posted liquidity. For example, BATS Global Markets (“BATS”) and Direct Edge, which previously operated as ATSs and obtained exchange status in 2008 and 2010, respectively, provided certain market data at no charge on their Web sites in order to attract more order flow, and used revenue rebates from resulting additional executions to maintain low execution charges for their users.
The large number of SROs, ATSs, and internalizing broker-dealers that currently produce proprietary data or are currently capable of producing it provides further pricing discipline for proprietary data products. Each SRO, ATS, and broker-dealer is currently permitted to produce and sell proprietary data products, and many currently do or have announced plans to do so, including but not limited to the Exchange, NYSE, NYSE Arca, NASDAQ OMX, BATS, and Direct Edge.
The fact that proprietary data from ATSs, internalizing broker-dealers, and vendors can bypass SROs is significant in two respects. First, non-SROs can compete directly with SROs for the production and sale of proprietary data products. By way of example, BATS and NYSE Arca both published proprietary data on the Internet before registering as exchanges. Second, because a single order or transaction report can appear in an SRO proprietary product, a non-SRO proprietary product, or both, the amount of data available via proprietary products is greater in size than the actual number of orders and transaction reports that exist in the marketplace. With respect to NYSE MKT Integrated Feed, competitors offer close substitute products.
Those competitive pressures imposed by available alternatives are evident in the Exchange's proposed pricing.
In addition to the competition and price discipline described above, the market for proprietary data products is also highly contestable because market entry is rapid and inexpensive. The history of electronic trading is replete with examples of entrants that swiftly grew into some of the largest electronic trading platforms and proprietary data producers: Archipelago, Bloomberg Tradebook, Island, RediBook, Attain, TrackECN, BATS Trading and Direct Edge. As noted above, BATS launched as an ATS in 2006 and became an exchange in 2008, while Direct Edge began operations in 2007 and obtained exchange status in 2010.
In setting the proposed fees for the NYSE MKT Integrated Feed, the Exchange considered the competitiveness of the market for proprietary data and all of the implications of that competition. The Exchange believes that it has considered all relevant factors and has not considered irrelevant factors in order to establish fair, reasonable, and not unreasonably discriminatory fees and an equitable allocation of fees among all users. The existence of numerous alternatives to the Exchange's products, including proprietary data from other sources, and continued availability of the Exchange's separate data feeds at a lower price, ensures that the Exchange cannot set unreasonable fees, or fees that are unreasonably discriminatory, when vendors and subscribers can elect these alternatives or choose not to purchase a specific proprietary data product if the attendant fees are not justified by the returns that any particular vendor or data recipient would achieve through the purchase.
No written comments were solicited or received with respect to the proposed rule change.
The foregoing rule change is effective upon filing pursuant to Section 19(b)(3)(A)
At any time within 60 days of the filing of such proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings under Section 19(b)(2)(B)
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
FINRA is proposing to amend FINRA Rule 6433 (Minimum Quotation Size Requirements for OTC Equity Securities) to extend the Tier Size Pilot, which currently is scheduled to expire on December 11, 2015, until June 10, 2016.
The text of the proposed rule change is available on FINRA's Web site at
In its filing with the Commission, FINRA included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. FINRA has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
FINRA proposes to amend FINRA Rule 6433 (Minimum Quotation Size Requirements for OTC Equity Securities) (the “Rule”) to extend, until June 10, 2016, the amendments set forth in File No. SR-FINRA-2011-058 (“Tier Size Pilot” or “Pilot”), which currently are scheduled to expire on December 11, 2015.
The Tier Size Pilot was filed with the SEC on October 6, 2011,
The purpose of this filing is to extend the operation of the Tier Size Pilot until June 10, 2016, to provide FINRA with additional time to finalize its recommendation with regard to the Tier Size Pilot.
FINRA has filed the proposed rule change for immediate effectiveness. The operative date of the proposed rule change will be December 11, 2015.
FINRA believes that the proposed rule change is consistent with the provisions of Section 15A(b)(6) of the Act,
FINRA believes that the extension of the Tier Size Pilot until June 10, 2016, is consistent with the Act in that it would provide the Commission and FINRA with additional time to determine whether the pilot tiers should be made permanent.
FINRA does not believe that the proposed rule change will result in any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
Written comments were neither solicited nor received.
Because the foregoing proposed rule change does not: (i) Significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A) of the Act
A proposed rule change filed under Rule 19b-4(f)(6)
FINRA has asked the Commission to waive the 30-day operative delay so that the proposal may become operative immediately upon filing. The Commission believes that waiver of the operative delay is consistent with the protection of investors and the public interest because such waiver will allow the pilot program to continue without interruption. Therefore, the Commission designates the proposal operative upon filing.
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
All submissions should refer to File Number SR-FINRA-2015-051. 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 Web site (
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange proposes to amend its Options Pricing at Chapter XV, Section 2, entitled “BX Options Market—Fees and Rebates,” which governs pricing for BX members using the BX Options Market (“BX Options”). The Exchange proposes to adopt new subsection (5) to add fees and rebates for BX Price Improvement Auction (“PRISM”), which is a mechanism for price improvement on BX Options (“Price Improvement Mechanism”).
While the changes proposed herein are effective upon filing, the Exchange has designated that the amendments be operative on November 16, 2015.
The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The Exchange proposes to amend its Chapter XV, Section 2 to adopt new subsection (5) to add fees and rebates for PRISM.
Effective on or about November 16, 2015, BX Options is introducing PRISM, which is codified in BX Chapter VI, Section 9 (also known as the “PRISM Rule”).
The Exchange believes that the PRISM Auction will be beneficial to market participants, and in particular will encourage BX Market Makers
This proposal establishes the fee and rebate structure for PRISM (per contract), in particular two new fees and one new rebate. These would apply to Customers,
Each specific change is described in detail below.
For Submitted PRISM Order the Exchange is proposing to establish fees for Agency Order (per contract), and fees for Contra-Side Order (per contract). Currently, the Exchange has no such fees.
The fees for Submitted PRISM Order will range from $0.00 to $0.30 for Agency Order. The fees for Submitted PRISM Order will range from $0.00 to $0.05 for Contra-Side Order. Specifically, for Submitted PRISM Order proposed Chapter XV, Section 2 subsection (5) will state that for Customer there will be no fee ($0.00) for Agency Order and no fee ($0.00) for Contra-Side Order. Subsection (5) will state that for BX Options Market Maker there will be a $0.30 fee for Agency Order and a $0.05 fee for Contra-Side Order. Subsection (5) will state that for Non-Customer there will be a $0.30 fee for Agency Order and a $0.05 fee for Contra-Side Order.
For Responded to PRISM Auction the Exchange is proposing to establish fees for Penny Classes (per contract), and fees for non-Penny Classes (per contract). Currently, the Exchange has no such fees.
The fees for Responded to PRISM Auction will be $0.49 (per executed contract) for Penny Classes. The fees for Responded to PRISM Auction will be $0.94 (per executed contract) for non-Penny Classes. Specifically, for Responded to PRISM Auction proposed Chapter XV, Section 2 subsection (5) will state that for Customer there will be a $0.49 fee for Penny Classes and a $0.94 fee for non-Penny Classes. Subsection (5) will state that for BX Options Market Maker there will be a $0.49 fee for Penny Classes and a $0.94 fee for non-Penny Classes. Subsection (5) will state that for Non-Customer there will be a $0.49 fee for Penny Classes and a $0.94 fee for non-Penny Classes.
For PRISM Order Traded with PRISM Response the Exchange is proposing to establish rebates for Penny Classes (per contract), and rebates for non-Penny Classes (per contract). Currently, the Exchange has no such rebates. These rebates would be applied in conjunction with the Agency Order fees that the Submitted PRISM Order is assessed.
The rebates for PRISM Order Traded with PRISM Response will range from $0.00 to $0.35 for Penny Classes. The rebates for PRISM Order Traded with PRISM Response will range from $0.00 to $0.70 for non-Penny Classes. Only Customers will get rebates. Specifically, for PRISM Order Traded with PRISM Response proposed Chapter XV, Section 2 subsection (5) will state that for Customer there will be a $0.35 rebate for Penny Classes and a $0.70 rebate for non-Penny Classes. Subsection (5) will state that for BX Options Market Maker and for Non-Customer there will be no rebate ($0.00) for Penny Classes and no rebate ($0.00) for non-Penny Classes.
A Customer PRISM Agency Order in a Penny Class (one contract) trades against a PRISM Response in a Penny Class (one contract). The Customer Agency Order is assessed a fee of $0.00 and given a rebate of $0.35 for a total rebate of $0.35 (fee $0.00 + rebate $0.35). The market participant that Responded to PRISM Auction will be assessed a fee of $0.49.
A Non-Customer PRISM Agency Order in a Penny Class (one contract) trades against a PRISM Response in a Penny Class (one contract). The Non-Customer Agency Order is assessed a fee of $0.30 and given a rebate of $0.00 for a total fee of $0.30 (fee $0.30 +
As proposed, Chapter XV, Section 2 subsection (5) will read as follows:
The Exchange is adopting these fees and rebates at this time because it believes that they will allow the Exchange to recoup some of the costs associated with PRISM, which promotes price improvement to the benefit of market participants, while also incentivizing the use of PRISM.
The Exchange believes that the proposed rule change is consistent with the provisions of Section 6 of the Act,
The Commission and the courts have repeatedly expressed their preference for competition over regulatory intervention in determining prices, products, and services in the securities markets. In Regulation NMS, for example, the Commission indicated that market forces should generally determine the price of non-core market data because national market system regulation “has been remarkably successful in promoting market competition in its broader forms that are most important to investors and listed companies.”
Further, “[n]o one disputes that competition for order flow is `fierce.' . . . As the SEC explained, `[i]n the U.S. national market system, buyers and sellers of securities, and the broker-dealers that act as their order-routing agents, have a wide range of choices of where to route orders for execution'; [and] `no exchange can afford to take its market share percentages for granted' because `no exchange possesses a monopoly, regulatory or otherwise, in the execution of order flow from broker dealers' . . . .”
The Exchange's proposal establishes fees and rebates regarding PRISM, which promotes price improvement to the benefit of market participants. The Exchange believes that PRISM will encourage market participants, and in particular BX Market Makers, to compete vigorously to provide the opportunity for price improvement in a competitive auction process. The Exchange believes that its proposal will allow the Exchange to recoup costs associated with PRISM while also incentivizing its use.
For Submitted PRISM Order, establishing that there will be no fee for Customer for Agency Order, while establishing a $0.30 fee per contract for BX Options Market Maker for Agency Order and a $0.30 fee per contract for Non-Customer for Agency Order, is reasonable because it encourages the desired Customer behavior. The fee is also reasonable because the associated revenue will allow the Exchange to maintain and enhance its services. For Submitted PRISM Order, establishing no Customer fee, while establishing a $0.05 fee per contract for BX Options Market Maker for Contra-Side Order and a $0.05 fee per contract fee for Non-Customer for Contra-Side Order, is reasonable because it encourages the desired Customer behavior. The fee is also reasonable because the associated revenue will allow the Exchange to maintain and enhance its services. Customer activity enhances liquidity on the Exchange for the benefit of all market participants and benefits all market participants by providing more trading opportunities, which attracts market makers. An increase in the activity of these market participants in turn facilitates tighter spreads, which may cause an additional corresponding increase in order flow from other market participants.
For Submitted PRISM Order, establishing no fee for Customer (Agency Order and Contra-Side Order) and a fee for BX Market Maker and Non-Customer (Agency Order and Contra-Side Order) is equitable and not unfairly discriminatory. This is because the Exchange's proposal to assess such fee will apply the same to all similarly situated participants.
For Responded to PRISM Auction, establishing that there will be a $0.49 fee per contract for Customer for Agency Order, and the same fee for BX Options Market Maker and for Non-Customer for Agency Order, is reasonable because the
For Responded to PRISM Auction, establishing that there will be a $0.94 fee per contract for Customer for Contra-Side Order, and the same fee for BX Options Market Maker and for Non-Customer for Contra-Side Order, is reasonable because the associated revenue will allow the Exchange to maintain and enhance its services.
For Responded to PRISM Auction, establishing a fee for Customer, BX Market Maker and Non-Customer (Agency Order and Contra-Side Order) is equitable and not unfairly discriminatory. This is because the Exchange's proposal to assess such fee will apply the same to all similarly situated participants.
For PRISM Order Traded with PRISM Response, establishing that there will be no rebate for BX Options Market Maker and Non-Customer for Penny Classes, while establishing a $0.35 rebate per contract for Customer for Penny Classes and a $0.70 rebate per contract for Customer for non-Penny Pilot Classes, is reasonable because it encourages the desired Customer behavior. The rebate is also reasonable because paying the rebate only to Customers will allow the Exchange to maintain and enhance its services. For PRISM Order Traded with PRISM Response, establishing that there will be no rebate for BX Options Market Maker and Non-Customer for non-Penny Classes, while establishing a $0.70 rebate per contract for Customer for non-Penny, is reasonable because it encourages the desired Customer behavior. The rebate is also reasonable because paying the rebate only to Customers will allow the Exchange to maintain and enhance its services.
For PRISM Order Traded with PRISM Response, establishing a rebate for Customer (Penny Classes and non-Penny Classes) and no rebate for BX Market Maker and Non-Customer (Penny Classes and non-Penny Classes) is equitable and not unfairly discriminatory. This is because the Exchange's proposal to pay such rebate will apply the same to all similarly situated participants. The Exchange is adopting the proposed fees and rebates at this time because it believes that the associated revenue will allow it to continue and enhance PRISM, which is beneficial to market participants.
The Exchange does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act. Specifically, the Exchange does not believe that its proposal to establish fees and rebates for PRISM will impose any burden on competition, as discussed below.
The Exchange operates in a highly competitive market in which many sophisticated and knowledgeable market participants can readily and do send order flow to competing exchanges if they deem fee levels or rebate incentives at a particular exchange to be excessive or inadequate. Additionally, new competitors have entered the market and still others are reportedly entering the market shortly. These market forces ensure that the Exchange's fees and rebates remain competitive with the fee structures at other trading platforms. In that sense, the Exchange's proposal is actually pro-competitive because the Exchange is simply establishing rebates and fees in order to remain competitive in the current environment.
The Exchange does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act. In terms of inter-market competition, the Exchange notes that it operates in a highly competitive market in which market participants can readily favor competing venues if they deem fee levels at a particular venue to be excessive, or rebate opportunities available at other venues to be more favorable. In such an environment, the Exchange must continually adjust its fees to remain competitive with other exchanges and with alternative trading systems that have been exempted from compliance with the statutory standards applicable to exchanges. Because competitors are free to modify their own fees in response, and because market participants may readily adjust their order routing practices, the Exchange believes that the degree to which fee changes in this market may impose any burden on competition is extremely limited.
In this instance, the proposed changes to the charges assessed and credits available to member firms in respect of PRISM do not impose a burden on competition because the Exchange's execution and routing services are completely voluntary and subject to extensive competition both from other exchanges and from off-exchange venues. If the changes proposed herein are unattractive to market participants, it is likely that the Exchange will lose market share as a result. Accordingly, the Exchange does not believe that the proposed changes will impair the ability of members or competing order execution venues to maintain their competitive standing in the financial markets. Additionally, the changes proposed herein are pro-competitive to the extent that they continue to allow the Exchange to promote and maintain PRISM, which has the potential to result in more efficient, price improved executions to the benefit of market participants.
No written comments were either solicited or received.
Pursuant to Section 19(b)(3)(A)(ii) of the Act,
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is: (i) Necessary or appropriate in the public interest; (ii) for the protection of investors; or (iii) otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule should be approved or disapproved.
Interested persons are invited to submit written data, views, and
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
All submissions should refer to File Number
Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule 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 Web site 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 10:00 a.m. and 3:00 p.m. Copies of the filing also will be available for inspection and copying at the principal office of the Exchange. All comments received will be posted without change; the Commission does not edit personal identifying information from submissions. You should submit only information that you wish to make available publicly.
All submissions should refer to File Number SR-BX-2015-071 and should be submitted on or before December 22, 2015.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Notice of request for public comment.
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.
The Department will accept comments from the public up to
You may submit comments by any of the following methods:
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You must include the DS form number (if applicable), information collection title, and the OMB control number in any correspondence.
Direct requests for additional information regarding the collection listed in this notice, including requests for copies of the proposed collection instrument and supporting documents, to Derek Rivers, Bureau of Consular Affairs, Overseas Citizens Services (CA/OCS/PMO), U.S. Department of State, SA-17, 10th Floor, Washington, DC 20036 or at
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We are soliciting public comments to permit the Department to:
• Evaluate whether the proposed information collection is necessary for the proper functions of the Department.
• 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.
• Enhance the quality, utility, and clarity of the information to be collected.
• Minimize the reporting burden on those who are to respond, including the use of automated collection techniques or other forms of information technology.
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.
The STEP makes it possible for U.S. nationals to register on-line from anywhere in the world. In the event of a family emergency, natural disaster or international crisis, U.S. embassies and consulates rely on this registration information to provide critical information and assistance to them. 22 U.S.C. 2715 is one of the main legal authorities that deem the usage of this form necessary.
99% of responses are received via electronic submission on the Internet. The service is available on the Department of State, Bureau of Consular Affairs Web site
Federal Railroad Administration (FRA), Department of Transportation (DOT)
Notice of Safety Advisory.
FRA is issuing Safety Advisory 2015-06 to notify freight railroads of the circumstances of a head-on collision at Hoxie, AR, and the risks automated inputs that reset alerter warning timing cycles pose. A small number of Union Pacific Railroad (UP) locomotives were equipped with alerters that the horn sequencer reset without direct engineer action, reducing the alerters' effectiveness. UP has appropriately modified its locomotives to resolve the issue and FRA is not aware of any other locomotives equipped with alerters that automatically reset without direct engineer action. However, all freight railroads should review the operation of their locomotives equipped with alerters, and modify them as necessary, to ensure no system resets the alerter warning timing cycle without direct engineer action.
Mr. Gary Fairbanks, Staff Director, Motive Power and Equipment Division, Office of Railroad Safety, FRA, 1200 New Jersey Avenue SE., Washington, DC 20590, (202) 493-6322; or Mr. Michael Masci, Trial Attorney, Office of Chief Counsel, FRA, 1200 New Jersey Avenue SE., Washington, DC 20590, (202) 493-6037.
A locomotive alerter is a safety feature installed on a locomotive to ensure the locomotive engineer remains alert while operating the locomotive. The alerter monitors the engineer's interactions with the locomotive and initially produces an alarm in the cab when no control actions are taken to reset the alerter warning timing cycle within a certain length of time. Because over-the-road locomotive operations often do not require frequent engineer actions (control inputs), alerter systems are also equipped with a manual reset button that allows the engineer to reset the warning timing cycle directly. If no control action or manual reset occurs after the alarm sounds, the alerter system will initiate a penalty brake application and reduce locomotive power to idle to stop the locomotive.
Horn activation is a locomotive control action that will reset the alerter warning timing cycle, but when automated (using a horn sequencer) it can also interfere with the alerter's normal functionality. On many locomotives, there are two distinct ways to activate the horn: (1) During ordinary operation, the engineer holds a manual horn controller in the “on” position to activate it, and then releases the controller to silence it; and (2) when approaching a crossing, the engineer activates a separate switch (often a foot pedal) to initiate an automatic horn sequencer (sounding the long-long-short-long sequence FRA's regulations require for public highway-rail grade crossings,
The head-on collision at Hoxie highlights the importance of this issue.
Given the recorded speed of the train, there were two intervals during horn sequencer operation when the alerter could have sounded, alerted the crew, and initiated a penalty brake application if no response was given. The evidence available does not rule out the possibility that the engineer was manually resetting the alerter on the lead locomotive. However, if the locomotive was set up the same as the trailing locomotive, which is likely, the alerter would not have reached its intended timing cycle limit before the actual impact, regardless whether the automatic activation of the horn sequencer reset the timing cycle. The interval from deactivation of the horn sequencer to impact was 44 seconds, or 9 seconds shorter than the alerter warning timing cycle interval of 53 seconds at the impact speed of 45 mph, so no alarm or penalty brake application could have occurred in this interval.
FRA cannot determine whether an alerter activation would have prevented the Hoxie collision. Yet, if the alerter had alarmed during the minutes leading up to the collision, it could have provided an opportunity to prevent or mitigate this accident. FRA tests of another locomotive in the same series verified that the horn sequencer installed in these locomotives reset the alerter warning timing cycle after each sounding of the horn, even though all but the first horn blast were initiated automatically. This series of 40 locomotives, which were built over 20 years ago, were factory-equipped with a stand-alone horn sequencer, wired to reset the alerter with every sounding of the horn, including the sounding of the horn by the horn sequencer.
UP has appropriately modified this series of locomotives to address this issue. FRA did not specifically regulate the manner of the alerter's interaction with the horn sequencer when the locomotives were manufactured. As discussed below, freight locomotives of
FRA safety regulations addressing alerters on freight locomotives are found at 49 CFR 229.140.
This section prohibits automatic systems from resetting the locomotive alerter. Specifically, 49 CFR 229.140(b)(3) requires movement of the engineer's horn activation handle to reset the alerter warning timing cycle. Using a horn sequencer to reset the alerter with each sounding of the horn (one for each of the long-long-short-long sequence) does not satisfy 49 CFR 229.140(b)(3), because all but the first horn blast are initiated automatically. This section requires engineers to take direct action, either by operation of certain controls or actuation of the manual reset, to restart the alerter warning timing cycle. Further, under 49 CFR 229.140(e), the alerter must be functioning and operating as intended when the locomotive is used. FRA addresses failures to comply with these regulatory requirements through inspections and enforcement activities.
Surface Transportation Board, DOT.
Correction to notice of exemption.
On October 9, 2015, Martin Marietta Materials, Inc. (MMM), a noncarrier, filed a verified notice of exemption to acquire control of Rock & Rail, Inc. (RRI), a Class III railroad. On October 23, 2015, notice of the exemption was served and published in the
On November 4, 2015, MMM filed a letter with the Board advising that the notice requires clarification. According to MMM, RRI also owns and operates rail lines in Colorado Springs, Colo.
Board decisions and notices are available on our Web site at “
By the Board, Rachel D. Campbell, Director, Office of Proceedings.
Notice and request for comments.
The Department of the Treasury, 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, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently the Bureau of the Fiscal Service within the Department of the Treasury is soliciting comments concerning the electronic process for selling/issuing, servicing, and making payments on or redeeming U.S. Treasury securities.
Written comments should be received on or before February 1, 2016 to be assured of consideration.
Direct all written comments to Bureau of the Fiscal Service, Bruce A. Sharp, 200 Third Street A4-A, Parkersburg, WV 26106-1328, or
Requests for additional information or copies of the form(s) and instructions should be directed to Ron Lewis; 200 Third Street Room 515, Parkersburg, WV 26106-1328, or
Office of Foreign Assets Control, Treasury.
Notice, publication of updated list of items defined as medical supplies.
The Department of the Treasury's Office of Foreign Assets Control (OFAC) is publishing an updated list of items defined as medical supplies under section 560.530(a)(3)(ii) of the Iranian Transactions and Sanctions Regulations, 31 CFR part 560, and generally licensed for exportation or reexportation to Iran pursuant to section 560.530(a)(3)(i), to include additional items.
The Department of the Treasury's Office of Foreign Assets Control: Assistant Director for Licensing, tel.: 202-622-2480, Assistant Director for Regulatory Affairs, tel.: 202-622-4855, Assistant Director for Sanctions Compliance & Evaluation, tel.: 202-622-2490; or the Department of the Treasury's Office of the Chief Counsel (Foreign Assets Control), Office of the General Counsel, tel.: 202-622-2410.
The text of the List of Medical Supplies and additional information concerning OFAC are available from OFAC's Web site (
On October 22, 2012, OFAC published a final rule in the
On April 7, 2014, OFAC published a final rule in the
As highlighted in the note to paragraph (a)(3)(ii) of section 560.530 of the ITSR, the List of Medical Supplies is maintained on OFAC's Web site and will be published in the
The list below comprises the medical supplies defined in 31 CFR 560.530(a)(3)(ii).
EAR99-classifed components, accessories, and optional equipment that are designed for and are for use with an EAR99-classified medical device included elsewhere on the list.
With this notice, OFAC is publishing the updated list of items defined as medical supplies in the
Office of Foreign Assets Control, Treasury.
Notice.
The U.S. Department of the Treasury's Office of Foreign Assets Control (OFAC) is publishing additional identifying information associated with the four individuals listed in the Annex to Executive Order 13712 of November 23, 2015, “Blocking Property of Certain Persons Contributing to the Situation in Burundi,” whose property and interests in property have been blocked.
Assistant Director for Licensing, tel.: 202-622-2480, Assistant Director for Regulatory Affairs, tel.: 202-622-4855, Assistant Director for Sanctions Compliance & Evaluation, tel.: 202-622-2490; or the Department of the Treasury's Office of the Chief Counsel (Foreign Assets Control), Office of the General Counsel, tel.: 202-622-2410.
OFAC's List of Specially Designated Nationals and Blocked Persons (“SDN List”) and additional information concerning OFAC sanctions programs are available from OFAC's Web site (
On November 23, 2015, the President issued Executive Order 13712, “Blocking Property of Certain Persons Contributing to the Situation in Burundi” (the “Order”) pursuant to,
The Annex to the Order lists four individuals whose property and interests in property are blocked pursuant to the Order. OFAC is publishing additional identifying information associated with those individuals.
The listings for these individuals on OFAC's SDN List appear as follows:
1. NDAYIRUKIYE, Cyrille; DOB 08 Jul 1954; POB Kiganda, Burundi; nationality Burundi; Gender Male; Passport DP0001029 (Burundi) issued 24 Oct 2011 expires 24 Oct 2016; Former Defense Minister (individual) [BURUNDI].
2. BUNYONI, Alain Guillaume (a.k.a. BUNYONI, Allain Guillaume), 143 Avenue Gasekebuye, Commune Urbaine de Musaga, Bujumbura, Bujumbura 1870, Burundi; DOB 02 Jan 1972; POB Bujumbura, Burundi; nationality Burundi; National ID No. 0201184751 (Burundi); Diplomatic Passport DP0001842 (Burundi) issued 08 Apr 2013 expires 08 Apr 2018; Minister of Public Security (individual) [BURUNDI].
3. BIZIMANA, Godefroid, Kinanira IV, Bujumbura, Burundi; DOB 23 Apr 1968; Diplomatic Passport DP0001520 (Burundi) issued 01 Aug 2012 expires 01 Aug 2017 (individual) [BURUNDI].
4. NIYOMBARE, Godefroid, Kinanira 4, Bujumbura, Bujumbura, Burundi; DOB 18 Oct 1969; POB Bujumbura, Burundi; nationality Burundi; Gender Male; Passport PD007079 (Burundi) issued 01 Jun 2010 expires 01 Jun 2015; National ID No. 0201CNI189976; Major General (individual) [BURUNDI].
Office of Foreign Assets Control, Treasury.
Notice.
The Treasury Department's Office of Foreign Assets Control (OFAC) is publishing the names of 10 persons whose property and interests in property are blocked pursuant to Executive Order (E.O.) 13582.
OFAC's actions described in this notice were effective on November 25, 2015, as further specified below.
Associate Director for Global Targeting, tel.: 202/622-2420, Associate Director for Sanctions Policy & Implementation, tel.: 202/622-2480, Office of Foreign Assets Control, or Chief Counsel (Foreign Assets Control), tel.: 202/622-2410, Office of the General Counsel, Department of the Treasury (not toll free numbers).
The Specially Designated Nationals and Blocked Persons List and additional information concerning OFAC sanctions programs are available on OFAC's Web site (
On November 25, 2015, OFAC blocked the property and interests in property of the following 10 persons pursuant to E.O. 13582, “Blocking Property of the Government of Syria and Prohibiting Certain Transactions with Respect to Syria”:
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, 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, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning PS-79-93 (TD 8633).
Written comments should be received on or before February 1, 2016 to be assured of consideration.
Direct all written comments to Christie Preston, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224. When sending comments please reference the information collection's title, form number, reporting or record-keeping requirement number, and OMB number (if any) in your comment.
Requests for additional information or copies of the collection tools should be directed to LaNita Van Dyke, Internal Revenue Service, Room 6517, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
Currently, the IRS is seeking comments concerning the following information collection tools, reporting, and record-keeping requirements:
The following paragraph applies to the collection of information covered by this notice:
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.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, 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, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Notice 2009-85, Guidance for Expatriates and Recipients of Foreign Source Gifts and Bequests Under Sections 877A, 2801, and 6039G;
Written comments should be received on or before February 1, 2016 to be assured of consideration.
Direct all written comments to Christie Preston, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224. Please reference the information collection's title, form number, reporting or record-keeping requirement number, and OMB number (if any) in your comment.
Requests for additional information or
Currently, the IRS is seeking comments concerning the following information collection tools, reporting, and recordkeeping requirements:
The following paragraph applies to all of the collection of information covered by this notice:
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.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, 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, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Arbitrage Restrictions on Tax-Exempt Bonds.
Written comments should be received on or before February 1, 2016 to be assured of consideration.
Direct all written comments to Michael Joplin, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of regulations should be directed to Kerry Dennis at Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet, at
Under section 148(f), interest on a state or local bond is not tax exempt unless the issuer of the bond rebates to the United States arbitrage profits earned from investing proceeds of the bond in higher yielding nonpurpose investments. Form 8038-T is used to pay the arbitrage rebate to the United States and to pay penalty in lieu of rebates. Burden for the form is being reported under 1545-1219.
Issuers are also required to keep records of certain interest rate hedges so that the hedges are taken into account in determining arbitrage profits. Under TD 8718, the scope of interest rate hedging transactions covered by the arbitrage regulations was broadened by requiring that hedges entered into prior to the sale date of the bonds are covered as well.
The collection of information in the proposed regulation (REG-138526-14) is in § 1.148-1(f)(2)(ii) which contains a requirement that the issuer obtain certifications and supporting documentation regarding the underwriter's sales of the issuer's bonds.
The following paragraph applies to all of the collections of information covered by this notice:
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.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, 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, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). The IRS is soliciting comments concerning information collection requirements related to Notice 2012-48, Tribal Economic Development Bonds.
Written comments should be received on or before February 1, 2016 to be assured of consideration.
Direct all written comments to Michael Joplin, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of notice should be directed to Sara Covington, at Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet, at
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to a collection of information unless the collection 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.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, 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, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Form 8918, Material Advisor Disclosure Statement.
Written comments should be received on or before February 1, 2016 to be assured of consideration.
Direct all written comments to Michael Joplin, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the form and instructions should be directed to Sara Covington, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
The following paragraph applies to all of the collections of information covered by this notice:
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.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, 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, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning an existing notice of proposed rulemaking and temporary regulations, FI-255-82 (TD 7852), Registration Requirements With Respect to Debt Obligations (§ 5f.103-1(c)).
Written comments should be received on or before February 1, 2016 to be assured of consideration.
Direct all written comments to Christie Preston, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of regulation should be directed to LaNita Van Dyke, Internal Revenue Service, Room 6517, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
The following paragraph applies to all of the collections of information covered by this notice:
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.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, 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
Written comments should be received on or before February 1, 2016 to be assured of consideration.
Direct all written comments to Michael Joplin Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the form and instructions should be directed to Sara Covington at Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
The following paragraph applies to all of the collections of information covered by this notice:
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.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, 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, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Notice 97-34, Information Reporting on Transactions With Foreign Trusts and on Large Foreign Gifts.
Written comments should be received on or before February 1, 2016 to be assured of consideration.
Direct all written comments to Michael Joplin, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of notice should be directed to Sara Covington, at Internal Revenue Service, room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
The following paragraph applies to all of the collections of information covered by this notice:
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.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, 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, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Revenue Procedure 2006-16, Renewal Community Depreciation Provisions.
Written comments should be received on or before February 1, 2016 to be assured of consideration.
Direct all written comments to Michael Joplin, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of revenue procedure should be directed to Sara Covington, at Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet, at
The following paragraph applies to all of the collections of information covered by this notice:
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.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, 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, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Form 8876, Excise Tax on Structured Settlement Factoring Transactions.
Written comments should be received on or before February 1, 2016 to be assured of consideration.
Direct all written comments to Christie Preston, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224. Please reference the information collection's title, form number, reporting or record-keeping requirement number, and OMB number (if any) in your comment.
Requests for additional information or copies of the collection tools should be directed to LaNita Van Dyke, Internal Revenue Service, Room 6517, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
Currently, the IRS is seeking comments concerning the following information collection tools, reporting, and record-keeping requirements:
The following paragraph applies to the collection of information covered by this notice:
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
Departmental Offices, Department of the Treasury.
Notice of reporting requirements.
By this Notice and in accordance with 31 CFR part 129, the Department of the Treasury is informing the public that it is conducting a mandatory survey of ownership of foreign securities by U.S. residents as of December 31, 2015. This Notice constitutes legal notification to all United States persons (defined below) who meet the reporting requirements set forth in this Notice that they must respond to, and comply with, this survey. The reporting form SHCA (2015) and instructions may be printed from the Internet at:
Corporate Senior Executive Management Office, Department of Veterans Affairs (VA).
Notice.
Under the provisions of 5 U.S.C. 4314(c)(4) agencies are required to publish a notice in the
Corporate Senior Executive Management Office, Department of Veterans Affairs, 810 Vermont Avenue NW., Washington, DC 20420.
Contact Tia N. Butler, Executive Director, Corporate Senior Executive Management Office (052), Department of Veterans Affairs, 810 Vermont Avenue NW., Washington, DC 20420, (202) 461-7865.
The membership of the Department of Veterans Affairs Performance Review Board is as follows: Robert L. Nabors II (Chair), A. Jacy Thurmond, Jr., David McLenachen, Richard Hipolit, Vivieca Simpson Wright, Bonnie Miranda, John Medve, Georgia Coffey, James Manker (Alternate), Tammy Czarnecki (Alternate), Edward Bradley (Alternate).
The Secretary of Veterans Affairs, or designee, approved this document 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. Robert L. Nabors II, Chief of Staff, Department of Veterans Affairs, approved this document on November 20, 2015, for publication.
Environmental Protection Agency (EPA).
Final rule.
This action finalizes the residual risk and technology review conducted for the Petroleum Refinery source categories regulated under national emission standards for hazardous air pollutants (NESHAP) Refinery MACT 1 and Refinery MACT 2. It also includes revisions to the Refinery MACT 1 and MACT 2 rules in accordance with provisions regarding establishment of MACT standards. This action also finalizes technical corrections and clarifications for the new source performance standards (NSPS) for petroleum refineries to improve consistency and clarity and address issues related to a 2008 industry petition for reconsideration. Implementation of this final rule will result in projected reductions of 5,200 tons per year (tpy) of hazardous air pollutants (HAP) which will reduce cancer risk and chronic health effects.
This final action is effective on February 1, 2016. The incorporation by reference of certain publications for part 63 listed in the rule is approved by the Director of the Federal Register as of February 1, 2016. The incorporation by reference of certain publications for part 60 listed in the rule were approved by the Director of the Federal Register as of June 24, 2008.
The Environmental Protection Agency (EPA) has established a docket for this action under Docket ID No. EPA-HQ-OAR-2010-0682. All documents in the docket are listed on the
For questions about this final action, contact Ms. Brenda Shine, Sector Policies and Programs Division, Refining and Chemicals Group (E143-01), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina, 27711; telephone number: (919) 541-3608; fax number: (919) 541-0246; and email address:
Table 1 of this preamble is not intended to be exhaustive, but rather to provide a guide for readers regarding entities likely to be affected by the final action for the source categories listed. To determine whether your facility is affected, you should examine the applicability criteria in the appropriate NESHAP or NSPS. If you have any questions regarding the applicability of any aspect of these NESHAP or NSPS, please contact the appropriate person listed in the preceding
In addition to being available in the docket, an electronic copy of this final action will also be available on the Internet through the Technology Transfer Network (TTN) Web site, a forum for information and technology exchange in various areas of air pollution control. Following signature by the EPA Administrator, the EPA will post a copy of this final action at:
Additional information is available on the RTR Web site at
Under CAA section 307(b)(1), judicial review of this final action is available only by filing a petition for review in the United States Court of Appeals for the District of Columbia Circuit by February 1, 2016. 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 the requirements.
Section 307(d)(7)(B) of the CAA further provides that “[o]nly an objection to a rule or procedure which was raised with reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review.” This section also provides a mechanism for the EPA to reconsider the rule “[i]f the person raising an objection can demonstrate to the Administrator 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, U.S. EPA, Room 3000, WJC Building, 1200 Pennsylvania Ave. NW., Washington, DC 20460, with a copy to both the person(s) listed in the preceding
Section 112 of the CAA establishes a two-stage regulatory process to address emissions of hazardous air pollutants (HAP) from stationary sources. In the first stage, we must identify categories of sources emitting one or more of the HAP listed in CAA section 112(b) and then promulgate technology-based NESHAP for those sources. “Major sources” are those that emit, or have the potential to emit, any single HAP at a rate of 10 tons per year (tpy) or more, or 25 tpy or more of any combination of HAP. For major sources, these standards are commonly referred to as maximum achievable control technology (MACT) standards and must reflect the maximum degree of emission reductions of HAP achievable (after considering cost, energy requirements, and non-air quality health and environmental impacts). In developing MACT standards, CAA section 112(d)(2) directs the EPA to consider the application of measures, processes, methods, systems or techniques, including but not limited to those that reduce the volume of or eliminate HAP emissions through process changes, substitution of materials, or other modifications; enclose systems or processes to eliminate emissions; collect, capture, or treat HAP when released from a process, stack, storage, or fugitive emissions point; are design, equipment, work practice, or operational standards; or any combination of the above.
For these MACT standards, the statute specifies certain minimum stringency requirements, which are referred to as MACT floor requirements, and which may not be based on cost considerations. See CAA section 112(d)(3). For new sources, the MACT floor cannot be less stringent than the emission control achieved in practice by the best-controlled similar source. The MACT standards for existing sources can be less stringent than floors for new sources, but they cannot be less stringent than the average emission limitation achieved by the best-performing 12-percent of existing sources in the category or subcategory (or the best-performing 5 sources for categories or subcategories with fewer than 30 sources). In developing MACT standards, we must also consider control options that are more stringent than the floor, under CAA section 112(d)(2). We may establish standards more stringent than the floor, based on the consideration of the cost of achieving the emissions reductions, any non-air quality health and environmental impacts, and energy requirements.
In the second stage of the regulatory process, the CAA requires the EPA to undertake 2 different analyses, which we refer to as the technology review and the residual risk review. Under the technology review, we must review the technology-based standards and revise them “as necessary (taking into account developments in practices, processes, and control technologies)” no less frequently than every eight years, pursuant to CAA section 112(d)(6). Under the residual risk review, we must evaluate the risk to public health remaining after application of the technology-based standards and revise the standards, if necessary, to provide an ample margin of safety to protect public health or to prevent, taking into consideration costs, energy, safety and other relevant factors, an adverse environmental effect. The residual risk review is required within eight years after promulgation of the technology-based standards, pursuant to CAA section 112(f). In conducting the residual risk review, if the EPA determines that the current standards provide an ample margin of safety to protect public health, it is not necessary to revise the MACT standards pursuant to CAA section 112(f).
Section 111 of the CAA establishes mechanisms for controlling emissions of air pollutants from stationary sources. Section 111(b) of the CAA provides authority for the EPA to promulgate NSPS that apply only to newly constructed, reconstructed and modified sources. Once the EPA has elected to set NSPS for new and modified sources in a given source category, CAA section 111(d) calls for regulation of existing sources, with certain exceptions explained below.
Specifically, section 111(b) of the CAA requires the EPA to establish emission standards for any category of new and modified stationary sources that the Administrator, in his or her judgment, finds “causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” The EPA has previously made endangerment findings under this section of the CAA for more than 60 stationary source categories and subcategories that are now subject to NSPS.
Section 111 of the CAA gives the EPA significant discretion to identify the affected facilities within a source category that should be regulated. To define the affected facilities, the EPA can use size thresholds for regulation and create subcategories based on source type, class or size. Emission limits also may be established either for equipment within a facility or for an entire facility. For listed source categories, the EPA must establish “standards of performance” that apply
The EPA also has significant discretion to determine the appropriate level for the standards. Section 111(a)(1) of the CAA provides that NSPS are to reflect the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any non-air quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated. This level of control is commonly referred to as best demonstrated technology (BDT) or the best system of emission reduction (BSER). The standard that the EPA develops, based on the BSER achievable at that source, is commonly a numerical emission limit, expressed as a performance level (
Costs are also considered in evaluating the appropriate standard of performance for each category or subcategory. The EPA generally compares control options and estimated costs and emission impacts of multiple, specific emission standard options under consideration. As part of this analysis, the EPA considers numerous factors relating to the potential cost of the regulation, including industry organization and market structure, control options available to reduce emissions of the regulated pollutant(s) and costs of these controls.
The EPA promulgated the petroleum refinery NESHAP pursuant to CAA section 112(d)(2) and (3) for refineries located at major sources in two separate rules. On August 18, 1995, the first petroleum refinery MACT standard was promulgated in 40 CFR part 63, subpart CC (60 FR 43620). This rule is known as “Refinery MACT 1” and covers the “Sources Not Distinctly Listed,” meaning it includes all emissions sources from petroleum refinery process units, except those listed separately under the section 112(c) source category list and expected to be regulated by other MACT standards (for example, boilers and process heaters). Some of the emission sources regulated in Refinery MACT 1 include miscellaneous process vents (MPV), storage vessels, wastewater, equipment leaks, gasoline loading racks, marine tank vessel loading and heat exchange systems.
On April 11, 2002 (67 FR 17762), EPA promulgated a second MACT standard regulating certain process vents that were listed as a separate source category under CAA section 112(c) and that were not addressed as part of the Refinery MACT 1. This standard, which is referred to as “Refinery MACT 2”, covers process vents on catalytic cracking units (CCU) (including FCCU), CRU and SRU and is codified as 40 CFR part 63, subpart UUU.
Finally, on October 28, 2009, we revised Refinery MACT 1 by adding MACT standards for heat exchange systems, which the EPA had not addressed in the original 1995 Refinery MACT 1 rule (74 FR 55686). In this same 2009 action, we updated the cross-references to the General Provisions in 40 CFR part 63. On June 20, 2013 (78 FR 37133), we promulgated minor revisions to the heat exchange provisions of Refinery MACT 1.
On September 27, 2012, Air Alliance Houston, California Communities Against Toxics and other environmental and public health groups filed a lawsuit alleging that the EPA missed statutory deadlines to review and revise Refinery MACT 1 and 2. The EPA reached an agreement to settle that litigation and entered into a Consent Decree. The Consent Decree provides for the Administrator to sign a final action no later than September 30, 2015.
Refinery NSPS subparts J and Ja regulated criteria pollutant emissions, including particulate matter (PM), sulfur dioxide (SO
The NSPS for petroleum refineries (40 CFR part 60, subpart J) were promulgated in 1974, amended in 1976 and amended again in 2008, following a review of the standards. As part of the review that led to the 2008 amendments to the Refinery NSPS subpart J, the EPA developed separate standards of performance for new process units (40 CFR part 60, subpart Ja). However, the EPA received multiple petitions for reconsideration on issues related to those standards. The Administrator granted the petitions for reconsideration. The EPA addressed petition issues related to process heaters and flares by promulgating amendments to the Refinery NSPS subparts J and Ja on September 12, 2012 (77 FR 56422). In this action, we are finalizing technical corrections and clarifications to NSPS subparts J and Ja raised by American Petroleum Institute (API) in their 2008 petition for reconsideration that were not addressed by the final NSPS amendments of 2012.
The petroleum refining industry consists of facilities that engage in converting crude oil into refined products, including liquefied petroleum gas, gasoline, kerosene, aviation fuel, diesel fuel, fuel oils, lubricating oils and feedstocks for the petrochemical industry. Currently, 142 facilities have emission sources regulated by either or both Refinery MACT 1 and 2.
Petroleum refinery activities start with the receipt of crude oil for storage at the refinery, include all the petroleum handling and refining operations, and terminate with loading of refined products into pipelines, tank or rail cars, tank trucks, or ships or barges that take products from the refinery to distribution centers. Petroleum-specific process units include FCCU and CRU. Other units and processes found at petroleum refineries (as well as at many other types of manufacturing facilities) include storage vessels and wastewater treatment plants. HAP emitted by this industry include organics (
On June 30, 2014, the EPA published a proposed rule in the
(1) Pursuant to CAA sections 112(d)(2) and (3):
a.
• Adding MACT Standards for DCU decoking operations.
• Adding operational requirements for flares used as APCD in Refinery MACT 1 and 2.
• Adding requirements and clarifications for vent control bypasses in Refinery MACT 1.
b.
• Revising the CRU purge vent exemption.
(2) Pursuant to CAA sections 112(d)(6) and 112(f)(2):
• Revising Refinery MACT 1 to cross-reference the corresponding storage vessel requirements in the Generic MACT (40 CFR part 63, subpart WW, as applicable), and revising the definition of Group 1 storage vessels to include smaller capacity storage vessels and to include storage vessels storing materials with lower vapor pressures.
(3) Pursuant to CAA section 112(d)(6):
a.
• Allowing refineries to meet the leak detection and repair (LDAR) requirements in Refinery MACT 1 by monitoring for leaks using optical gas imaging in place of EPA Method 21, once the monitoring protocol set forth in Appendix K is promulgated.
• Amending the Marine Tank Vessel Loading Operations NESHAP, 40 CFR part 63, subpart Y, to delete the exclusion for marine vessel loading operations at petroleum refineries.
• Establishing a fenceline monitoring work practice standard to improve the management of fugitive emissions.
b.
• Incorporating requirements consistent with those in Refinery NSPS subpart Ja for FCCU including:
• Requiring the use of 3-hour averages rather than daily averages for parameter operating limits (
• Removing the Refinery NSPS subpart J incremental PM emissions allowance for post combustion devices when burning liquid or solid fuels, and removing the 30 percent opacity limit for units complying with NSPS subpart J.
• Adding requirements for FCCU controls to include bag leak detectors (BLD) as an option to continuous opacity monitoring system (COMS).
• Incorporating total power and the secondary current operating limits for electrostatic precipitators (ESP).
• Requiring daily checks of the air or water pressure to the spray nozzles on jet ejector-type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles.
• Requiring FCCU periodic performance testing on a frequency of once every 5 years, as opposed to the current rule, which only requires an initial performance test.
• Including a correlation equation for the use of oxygen-enriched air for SRU.
• Allowing SRU subject to Refinery NSPS subpart Ja with a capacity greater than 20 long tons per day (LTD) to comply with Refinery NSPS subpart Ja as a means of complying with Refinery MACT 2.
(4) Other proposed changes include:
• Removing exemptions from the rule requirements for periods of SSM in order to ensure that the NESHAP are consistent with the court decision in
• Clarifying requirements related to open-ended valves or lines.
• Adding electronic reporting requirements.
• Updating the General Provisions cross-reference tables.
• Making technical corrections and clarifications to NSPS subparts J and Ja.
This action finalizes the EPA's determinations pursuant to the RTR provisions of CAA section 112 for the Petroleum Refinery source categories and amends the Petroleum Refinery NESHAP based on those determinations. This action also finalizes other changes to the NESHAP including revising Refinery MACT 1 and 2 pursuant to CAA section 112 (d)(2) and (3), including revising requirements for flares and pressure relief devices (PRD). This action finalizes changes to the SSM provisions to ensure that the subparts are consistent with the court decision in
The EPA is promulgating final amendments to the Petroleum Refinery NESHAP pursuant to CAA section 112(f) that expand the existing Refinery MACT 1 control requirements and extend these requirements to smaller tanks and tanks with lower vapor pressures. Specifically, consistent with the proposal, the EPA is amending Refinery MACT 1 by revising the definition of Group 1 storage vessels to include storage vessels with capacities greater than or equal to 20,000 gallons but less than 40,000 gallons if the maximum true vapor pressure is 1.0 psia or greater and to include storage tanks greater than 40,000 gallons if the maximum true vapor pressure is 0.75 psia or greater. The EPA is also adding a cross-reference to the storage vessel requirements in the Generic MACT (40 CFR part 63, subpart WW and subpart CC), which include requirements for guide pole controls and other fittings as well as inspection requirements. After considering the public comments, the final amendments include minor changes from our proposed requirements to clarify language and correct typographical and referencing errors.
We determined that there are developments in practices, processes and control technologies that warrant revisions to the MACT standards for this source category. Therefore, to satisfy the requirements of CAA section 112(d)(6), we are revising the MACT standards to amend 40 CFR part 63, subpart Y to delete the exclusion for marine vessel loading operations at petroleum refineries. Removing this exclusion will require small marine vessel loading operations (
We are also finalizing a fenceline monitoring work practice standard to improve the management of fugitive emissions and finalizing EPA Methods 325A and 325B to support the work
We determined that there are developments in practices, processes and control technologies that warrant revisions to the MACT standards for this source category. Therefore, to satisfy the requirements of CAA section 112(d)(6), we are revising the Refinery MACT 2 standard for FCCU subject to Refinery NSPS subpart J or those electing to comply with the Refinery NSPS subpart J requirements. As proposed, we are removing the incremental PM limit when burning liquid or solid fuels. We are finalizing a 20-percent opacity operating limit evaluated on a 3-hour average, which differs from the proposal to eliminate the 30-percent opacity limit and instead allow only for a site-specific opacity operating limit or control device parameter monitoring. As proposed, we are finalizing requirements to make Refinery MACT 2 consistent with Refinery NSPS subpart Ja for FCCU by including 3-hour averages rather than daily averages for parameter operating limits, and by including 3-hour averages rather than daily averages for the site-specific opacity operating limit. We are also finalizing requirements, as proposed, for FCCU controls to include adding BLD as an option to COMS, incorporating total power and the secondary current operating limits for ESP and requiring daily checks of the air or water pressure to the spray nozzles on jet ejector-type wet scrubbers or other types of wet scrubbers equipped with atomizing spray nozzles.
Finally, we are finalizing, as proposed, requirements for FCCU periodic performance testing at a frequency of once every 5 years rather than the current requirements for a one-time initial performance test. However, for owners or operators complying with the Refinery NSPS subpart J option (with the 20-percent opacity operating limit discussed above), if the PM emissions are within 80-percent of the PM limit during any periodic performance test (
For SRU, as proposed, we are finalizing a correlation equation for the use of oxygen-enriched air. Additionally, as proposed, we are finalizing requirements to allow sulfur recovery plants subject to Refinery NSPS subpart Ja with a capacity greater than 20 LTD to comply with Refinery NSPS subpart Ja as a means of complying with Refinery MACT 2.
We are finalizing MACT standards for DCU decoking operations that require that each coke drum be depressured to a closed blowdown system until the coke drum pressure is 2 psig with minor revisions from proposal. Specifically, we are finalizing provisions for existing DCU affected sources to average over a 60-cycle (
We are finalizing operational requirements and the associated monitoring, recordkeeping and reporting requirements for flares used as APCD in Refinery MACT 1 and 2 with revisions to the requirements proposed. Prior to these amendments, Refinery MACT 1 and 2 cross-referenced the General Provisions requirements at 40 CFR 63.11(b). As proposed, this final action replaces the cross reference to the General Provisions and incorporates enhanced flare operational requirements directly into the Refinery MACT regulations. As proposed, the final rule amendments require that refinery flares operate with continuously lit pilot flames at all times. Consistent with our proposal, we are finalizing requirements for flares to operate with no visible emissions and comply with consolidated requirements related to flare tip velocity, but in the final rule these direct emissions limits apply when flare vent gas flow is below the smokeless capacity of the flare rather than at all times. Above the smokeless capacity of the flare, we are establishing a work practice standard related to the visible emissions and velocity limits; these work practice standards are described in more detail in section III.D.1 of this preamble.
We are finalizing new operational requirements related to combustion zone gas properties with revisions from proposal. In response to comments on the proposal, we are finalizing requirements that flares meet a minimum operating limit of 270 BTU/scf NHVcz on a 15-minute average, and are allowing refinery owners or operators to use a corrected heat content of 1,212 BTU/scf for hydrogen to demonstrate compliance with this operating limit. We had proposed two separate sets of limits, one being more stringent if an olefins/hydrogen mixture was present in the waste gas. For each set of limits, we proposed three different alternative combustion zone operating limits: One based on the combustion zone net heat content with no correction for the heat content of hydrogen, one based on the lower flammability limit and one based on the combustibles concentration. We proposed that these limits be determined on a 15-minute “feed-forward” block average approach (
As proposed, we are also finalizing in this rule a burden reduction option to use grab sampling every 8 hours rather than continuous vent gas composition or heat content monitors. We are also including, based on public comment, provisions to conduct limited initial sampling and process knowledge to characterize flare gas composition for flares in “dedicated” service as an alternative to collecting grab samples during each specific event. We are finalizing a requirement for daily visible emissions observations as proposed, but, based on public comment, we are allowing owners or operators to use video surveillance cameras to demonstrate compliance with the visible emissions limit as an alternative to the daily visible emissions observations.
For PRD, we are finalizing requirements for monitoring systems that are capable of identifying and recording the time and duration of each pressure release to the atmosphere, as proposed. Certain PRD with low set pressures or low emission potential or in liquid service would not be subject to these monitoring requirements. We are finalizing requirements to minimize or prevent atmospheric releases of HAP through PRD. Instead of the proposed prohibition on such releases, we are finalizing work practice requirements that require both preventive measures as well as root cause analysis and corrective action that will incentivize refinery owners or operators to eliminate the causes of the releases.
We are finalizing requirements for bypass lines with minor revisions from those proposed. Specifically, we are not adopting the proposed requirement to install quantitative flow monitors and thus are leaving in place the requirement to use flow indicators on bypass lines. In addition, we are maintaining the requirements to estimate and report the quantity of organic HAP released. In response to public comment, we are also clarifying changes to remove the proposed reference to air intrusion and specifying that reporting of bypasses is only required when “regulated material” is discharged to the atmosphere as a result of a bypass of a control device.
We are also finalizing revisions to the definition of miscellaneous process vent, as proposed. These revisions include deletion of exclusions associated with episodic releases and vents from in situ sampling systems. As proposed, the final amendments require that these vents must meet the standards applicable to MPV.
For CRU vents, we are finalizing the vessel pressure limit exclusion of 5 psig to apply only to passive depressurization, as proposed.
We are finalizing, as proposed, changes to Refinery MACT 1 and 2 to eliminate the SSM exemption. Consistent with
We are finalizing a work practice standard for PRD that requires refinery owners or operators to establish prevention measures for each PRD in organic HAP service. Under the work practice standard, where a direct release occurs, the refinery is required to perform root cause analysis and implement corrective action. The work practice standard also limits the number of events that a PRD may release to the atmosphere during a 3-year period, as explained further in the section IV.D. of this preamble.
We are also finalizing a work practice standard for emergency flaring events that requires refinery owners or operators to establish prevention measures, including the development of a flare management plan (FMP), and perform root cause analysis and implement corrective action following flaring events during which the velocity of waste gas going to the flare or visible emissions limits (
We are also finalizing requirements for opening process equipment to the atmosphere during maintenance events after draining and purging to a closed system, provided the hydrocarbon content is less than or equal to 10-percent of the lower explosive limit (LEL). For those situations where 10-percent LEL cannot be demonstrated, the equipment may be opened and vented to the atmosphere if the pressure is less than or equal to 5 psig, provided there is no active purging of the equipment to the atmosphere until the LEL criterion is met. This 5 psig allowance is only available during shutdown. We are also providing additional allowances for situations where it is not technically feasible to depressurize a control system where there is no more than 72 lbs VOC per day vented to the atmosphere, consistent with our Group 1 applicability cutoff for control of process vents, or for catalyst changeout activities where hydrotreater pyrophoric catalyst must be purged. Provisions to demonstrate that process equipment is opened only after the LEL, pressure or mass in the vessel requirement is met includes documenting the procedures for equipment openings and procedures for verifying that the openings meet the specific, above-discussed requirements using site-specific procedures used to de-inventory equipment for safety purposes (
The Refinery MACT 2 standards regulate all HAP emissions from the three refinery process vents subject to Refinery MACT 2. For FCCU, the standard specifies a CO limit as a surrogate for organic HAP and specifies a PM limit (or Ni limit) as a surrogate for metal HAP. Compliance with the organic HAP emissions limit is demonstrated using a continuous CO monitor; compliance with the metal HAP emissions limit is demonstrated using either COMS or control device parameter monitoring systems (CPMS). At proposal, with the removal of the exemptions in the Refinery MACT 2 rule for periods of startup and shutdown, we recognized the need for alternative standards during some startup and shutdown situations, and we proposed alternative requirements.
For this final rule, we are including a 1-percent minimum oxygen limit as an alternative to the 500 ppmv hourly CO limit during FCCU startup for partial
We are not finalizing the proposed alternative opacity limit for FCCU during startup. Instead, based on public comments received, we are finalizing an alternative minimum cyclone face velocity limit as a means to demonstrate compliance with the PM limit during both startup and shutdown, regardless of the type of FCCU and its control device. We are finalizing alternative standards for sulfur recovery plant (SRP) incinerator temperature and excess oxygen limits during SRP shutdown, as proposed, and we are extending the proposed alternative standards to startup as well.
We are finalizing technical amendments to NSPS subparts J and Ja with limited changes from what we proposed. First, in response to comments, we are revising the NSPS requirements that a flow sensor have a “measurement sensitivity” of no more than 5-percent of the flow rate to an “accuracy” requirement that the flow sensor have an accuracy of 5-percent of the flow rate. This change will make the requirements more clear and consistent between the flow meter requirements in the NSPS and the MACT standards since it is the same flow meter subject to these requirements. We are also revising flare flow rate accuracy requirements in Refinery NSPS subpart Ja to make them consistent with those we are finalizing in Refinery MACT 1. Finally, we are revising 40 CFR 60.101a(b) to begin as “Except for flares and delayed coking units . . .” to correct an inadvertent error. We proposed revisions to this sentence solely to allow sources subject to Refinery NSPS subpart J to comply with the provisions in Refinery NSPS subpart Ja instead. However, the words “and delayed coking units” were inadvertently omitted from the initial part of the sentence. Thus, as intended, we are finalizing revisions to this sentence to allow sources subject to Refinery NSPS subpart J to comply with the provisions in Refinery NSPS subpart Ja.
As proposed, the EPA is taking a step to increase the ease and efficiency of data submittal and data accessibility. Specifically, the EPA is finalizing the requirement for owners or operators of Petroleum Refinery facilities to submit electronic copies of certain required performance test reports through the EPA's Central Data Exchange (CDX) using the Compliance and Emissions Data Reporting Interface (CEDRI). The EPA believes that the electronic submittal of the reports addressed in this rulemaking will increase the usefulness of the data contained in those reports, is in keeping with current trends in data availability, will further assist in the protection of public health and the environment and will ultimately result in less burden on the regulated community. Electronic reporting can also eliminate paper-based, manual processes, thereby saving time and resources, simplifying data entry, eliminating redundancies, minimizing data reporting errors and providing data quickly and accurately to the affected facilities, air agencies, the EPA and the public.
As mentioned in the preamble of the proposal, the EPA Web site that stores the submitted electronic data, WebFIRE, will be easily accessible to everyone and will provide a user-friendly interface that any stakeholder could access. By making the records, data and reports addressed in this rulemaking readily available, the EPA, the regulated community and the public will benefit when the EPA conducts its CAA-required technology and risk-based reviews. As a result of having reports readily accessible, our ability to carry out comprehensive reviews will be increased and achieved within a shorter period of time.
We anticipate fewer or less substantial information collection requests (ICRs) in conjunction with prospective CAA-required technology and risk-based reviews may be needed. We expect this to result in a decrease in time spent by industry to respond to data collection requests. We also expect the ICRs to contain less extensive stack testing provisions, as we will already have stack test data electronically. Reduced testing requirements would be a cost savings to industry. The EPA should also be able to conduct these required reviews more quickly. While the regulated community may benefit from a reduced burden of ICRs, the general public benefits from the agency's ability to provide these required reviews more quickly, resulting in increased public health and environmental protection.
Air agencies could benefit from more streamlined and automated review of the electronically submitted data. Having reports and associated data in electronic format will facilitate review through the use of software “search” options, as well as the downloading and analyzing of data in spreadsheet format. The ability to access and review air emission report information electronically will assist air agencies to more quickly and accurately determine compliance with the applicable regulations, potentially allowing a faster response to violations which could minimize harmful air emissions. This benefits both air agencies and the general public.
For a more thorough discussion of electronic reporting required by this rule, see the discussion in the preamble of the proposal. In summary, in addition to supporting regulation development, control strategy development, and other air pollution control activities, having an electronic database populated with performance test data will save industry, air agencies, and the EPA significant time, money, and effort while improving the quality of emission inventories, air quality regulations, and enhancing the public's access to this important information.
The final amendments to the NESHAP and NSPS in this action are effective on February 1, 2016. As proposed, new sources must comply with these requirements by the effective date of the final rule or upon startup, whichever is later.
As proposed, existing sources are required to comply with the final DCU and CRU requirements no later than 3 years after the effective date of the final rule. Similarly, as proposed, owners or operators are required to comply with the new operating and monitoring requirements for existing flares no later than 3 years after the effective date of the final rule.
We proposed to provide 3 years from the effective date of the final rule for refinery owners or operators to install and begin monitoring (collecting samples) around the fenceline of their existing facility. If refinery owners and operators determined that a site-specific monitoring plan was needed, they would also need to submit and receive approval for such a plan during the 3-year compliance period. Based on information submitted during the comment period, we are finalizing requirements that refinery owners or operators begin collecting samples around the fenceline within 2 years of the effective date of the final rule. Based on information submitted during the comment period, 1 year is sufficient time to identify proper monitoring locations and to install the required monitoring stations around the facility
As proposed, we are requiring that existing sources comply with the submerged filling requirement for marine vessel loading on the effective date of the final rule.
As proposed, we are providing 18 months after the effective date of the final rule to conduct required performance tests and comply with any revised operating limits for FCCU.
We proposed to require refinery owners or operators to comply with the revisions to the SSM provisions of Refinery MACT 1 and 2 on the effective date of the final rule. As proposed, this final rule requires refinery owners or operators to comply with the limits in Refinery MACT 2 or the alternative limits in this final rule during startup and shutdown for FCCU and SRU on the effective date of the final rule.
The flare work practice standards for high-load flaring events (events exceeding the smokeless capacity of the flare) require development of FMP (or revision of an existing plan) to specifically consider emergency shutdown and other high load events. In this FMP, refinery owners or operators must consider measures that can be implemented to reduce the frequency and magnitude of these high-load flaring events. This may include installation of a flare gas recovery system. Additionally, the work practice standards will require refinery owners or operators to identify and implement measures that may involve process changes. Therefore, we are establishing a compliance date of 3 years from the effective date of the final rule for refinery owners or operators to comply with the work practice standards for high load flaring events. We also note that this compliance period is consistent with the compliance time provided for the flare operating limits.
For atmospheric PRD in HAP service we are establishing a work practice standard that requires a process hazard analysis and implementation of a minimum of three redundant measures to prevent atmospheric releases. Alternately, refinery owners or operators may elect to install closed vent systems to route these PRD to a flare, drain (for liquid thermal relief valves) or other control system. We anticipate that sources will need to identify the most appropriate preventive measures or control approach; design, install and test the system; install necessary process instrumentation and safety systems; and may need to time installations with equipment shutdown or maintenance outages. Therefore, we have established a compliance date of 3 years from the effective date of the final rule for refinery owners or operators to comply with the work practice standards for atmospheric PRD.
As proposed, we are requiring compliance with the electronic reporting provisions for performance tests conducted for Refinery MACT 1 and 2 on the effective date of the final rule.
Finally, we are finalizing additional requirements for storage vessels under CAA sections 112(d)(6) and (f)(2) with a compliance date 90 days after the effective date of the final rule, as proposed.
In this final rule, the EPA is including regulatory text that includes incorporation by reference. In accordance with requirements of 1 CFR 51.5, the EPA is incorporating by reference the following documents described in the amendments to 40 CFR 63.14:
• ASTM D1945-03 (Reapproved 2010), Standard Test Method for Analysis of Natural Gas by Gas Chromatography, (Approved January 1, 2010).
• ASTM D1945-14, Standard Test Method for Analysis of Natural Gas by Gas Chromatography.
• ASTM D6196-03 (Reapproved 2009), Standard Practice for Selection of Sorbents, Sampling, and Thermal Desorption Analysis Procedures for Volatile Organic Compounds in Air, (Approved March 1, 2009).
• ASTM D6348-03 (Reapproved 2010), Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, including Annexes A1 through A8, (Approved October 1, 2010).
• ASTM D6348-12e1, Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy.
• ASTM D6420-99 (Reapproved 2010), Standard Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography-Mass Spectrometry.
• ASTM UOP539-12, Refinery Gas Analysis by GC.
• BS EN 14662-4:2005, Ambient air quality—Standard method for the measurement of benzene concentrations—Part 4: Diffusive sampling followed by thermal desorption and gas chromatography, June 27, 2005.
• EPA-454/B-08-002, Quality Assurance Handbook for Air Pollution Measurement Systems, Volume IV: Meteorological Measurements, Version 2.0 (Final), March 2008.
• EPA-454/R-99-005, Meteorological Monitoring Guidance for Regulatory Modeling Applications, February 2000.
• ISO 16017-2:2003(E): Indoor, ambient and workplace air—Sampling and analysis of volatile organic compounds by sorbent tube/thermal desorption/capillary gas chromatography—Part 2: Diffusive sampling, May 15, 2003.
• Air Stripping Method (Modified El Paso Method) for Determination of Volatile Organic Compound Emissions from Water Sources” Revision Number One, dated January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, prepared by Texas Commission on Environmental Quality, January 31, 2003.
The EPA has made, and will continue to make, these documents available electronically through
The results of our residual risk review for the Petroleum Refinery source categories were published in the June 30, 2014 proposal at (79 FR 36934 through 36942), and included assessment of chronic and acute inhalation risk, as well as multipathway and environmental risk, to inform our decisions regarding acceptability and ample margin of safety. The results indicated that both the actual and
As part of the final risk assessment, we conducted a screening level analysis of how the information we received during the public comment period, along with the changes we are making to the proposed rule, would change our proposed risk estimates (More details can be found in the “Final Residual Risk Assessment for the Petroleum Refining Source Sector”, Docket ID No. EPA-HQ-OAR-2010-0682).
First, we received approximately 20 emissions inventory updates for specific facilities. These updates included revised emission estimates, revised release latitude/longitude locations and other release characteristic revisions. The updates provided evidence that the quantity of HAP emitted at these specific facilities is lower than considered in the risk modeling for the proposed rule. Our assessment of the effects of these changes suggests that the cancer maximum individual risk (MIR) based on actual emissions may be closer to 40-in-1 million, as opposed to 60-in-1 million, as projected at proposal. We did not quantify the reductions in chronic or acute non-cancer risks from these updates. We calculated allowable emissions using the Refinery Emissions Model (REM), which estimates emissions based on each refinery's capacities and throughputs [See discussion at 79 FR 36888, June 30, 2014.] The allowable emission estimates for point and fugitive sources were not specific to a particular latitude/longitude location so we assumed them to release from the centroid of the facility. Therefore, the predicted cancer MIR of approximately 100-in-1 million based on allowable emissions and reported in the proposal risk characterization does not change based on the submitted emissions revisions. We did not quantify changes to other actual risk metrics as part of the screening level analysis (
Second, we are establishing work practice standards in the final rule for PRD releases and emergency flaring events, which under the proposed rule would not have been allowed. Thus, because we did not consider such non-routine emissions under our risk evaluation for the proposed rule, we performed a screening assessment of risk associated with these non-routine events for the final rule. [We provide further details on the screening approach in “Final Residual Risk Assessment for the Petroleum Refining Source Sector” in Docket ID No. EPA-HQ-OAR-2010-0682.] We extracted information on these events from the 2011 Petroleum Refinery ICR data that included the process unit identification, mass of emissions, duration of release, and description of the incident. We identified the highest HAP mass releases for both PRDs and flares from these non-routine events. We assumed these HAP emission releases could occur at any facility in the source category. Our analysis suggests that these HAP emissions could increase the MIR based on actual emissions by as much as 2-in-1 million. Because the PRD and flaring events were the worst case HAP mass emission release events reported in the 2011 Refinery ICR for the source category, we are assuming that actual and allowable risks are no different for these events (
The screening analysis projects that the maximum predicted acute non-cancer risk from non-routine PRD and flare emissions results in a hazard quotient (HQ) based on a recommended reference exposure level limit (REL) of up to 14 from benzene emissions. While the analysis shows that there is a potential for HQs exceeding 1 for benzene, because of the many uncertainties and conservative nature of this screening analysis, the likelihood of such exposure and risk are low. At proposal, we projected a HQ based on the REL for benzene of up to 2 from routine emissions. If we conservatively combine the routine and non-routine emissions analyses, we would expect the potential for HQs based on the REL for benzene to have the potential to increase above 2. However, as projected at proposal, we estimate that the acute HQs calculated using acute exposure guideline levels (AEGL) and emergency response and planning guidelines (ERPG) values for all pollutants including benzene would still be well
Considering all of these factors, we do not project risks to be significantly different from what we proposed. Based on the risk analysis, as informed by the screening level analysis based on information obtained during the comment period, we are finalizing our determination that the risk remaining after promulgation of the NESHAP is acceptable.
We received numerous comments on the residual risk assessment analyses and results. We summarize the key comments received below, along with our responses. A complete summary of all public comments received and our responses are in the “Response to Comment” Document in the public docket (Docket ID No. EPA-HQ-OAR-2010-0682).
Other commenters stated the EPA's risk estimates are understated and that the EPA should reduce the benchmark of what it considers acceptable lifetime cancer risk instead of the upper limit of 100-in-1 million. One commenter provided an extensive critique of the cancer, chronic and acute affects levels used in the risk assessment and recommended that the EPA use California Office of Environmental Health Hazard Assessment's (OEHHA) new toxicity values for several chemicals. The commenter provided some references for the approaches used to derive the California values. The commenter also asserted that risks would be unacceptable had these more protective values been used in the risk assessment. Some commenters stated the risks from petroleum refinery emissions are underestimated because the EPA did not but should have included interaction of multiple pollutants, accounted for exposure to multiple sources, and assessed the cumulative risks from facility-wide emissions and multiple nearby sources impacting an area.
Regarding the comment that in light of the acceptability determination the proposed changes to the rule are not justified, we note that we also are required to ensure that the standards provide an ample margin of safety to protect public health. That analysis is separate from the acceptability analysis, and the determination of acceptability does not automatically lead us to conclude that the standards provide an ample margin of safety to protect public health.
Regarding the comments that the EPA should use the new California OEHHA values, we disagree. The EPA's chemical-specific toxicity values are derived using risk assessment guidelines and approaches that are well established and vetted through the scientific community, and follow rigorous peer review processes.
The EPA scientists reviewed the information provided by the commenter regarding the California values and concluded that further information is needed to evaluate the scientific basis and rationale for the recent changes in California OEHHA risk assessment methods. The EPA will work on gathering the necessary information to conduct an evaluation of the scientific merit and the appropriateness of the use of California OEHHA's new toxicity values in the agency decisions. Until the EPA has completed its evaluation, it is premature to determine what role these values might play in the RTR process. Therefore, the EPA did not use the new California OEHHA toxicity values as part of this current action. For more detailed responses regarding appropriate reference values for specific pollutants, see the “Response to Comment” document in the public docket (Docket ID No. EPA-HQ-OAR-2010-0682).
Concerning comments that we should consider aggregate risks from multiple pollutants and sources, we note that we have done this to the extent it is appropriate to do so. We modeled whole-facility risks for both chronic cancer and non-cancer impacts to understand the risk contribution of the sources within the Petroleum Refinery source categories. The individual cancer risks for the source categories were aggregated for all carcinogens. In assessing non-cancer hazard from chronic exposures to pollutants that have similar modes of action or (where this information is absent) that affect the same target organ, we summed the HQs. This process creates, for each target organ, a TOSHI, defined as the sum of HQs for individual HAP that affect the same organ or organ system. Whole-facility risks were estimated based on the 2011 ICR emissions data obtained from facilities, which included emissions from all sources at the refinery, not just Refinery MACT 1 and 2 emission sources (
Further, the risk assessment modeling accounts for the effects of multiple facilities that may be in close proximity when estimating concentration and risk impacts at each block centroid. When evaluating the risks associated with a particular source category, we combined the impacts of all facilities within the same source category and assessed chronic exposure and risk for all census blocks with at least one resident (
The ICR-submitted information for allowable emissions did not include emission estimates for all HAP and all emission sources. Consequently, we used the REM to estimate allowable emissions. The REM relies on model plants that vary based on throughput capacity. Each model plant contains process-specific default emission factors, adjusted for compliance with the Refinery MACT 1 and 2 emission standards.
We agree with the commenters that studies have shown that many refinery flares are operating less efficiently than 98 percent. Prior to proposing this rule, we conducted a flare ad hoc peer review to advise the EPA on factors affecting flare performance (see discussion in the June 30, 2014, proposal at 79 FR 36905). However, we disagree with the commenters that the risk analysis should consider this level of performance since the existing MACT standard does not allow it. For purposes of the risk analysis, we evaluate whether it is necessary to tighten the existing MACT standard in order to provide an ample margin of safety. Thus, in reviewing whether the existing standards provide an ample margin of safety, we review the level of emissions the MACT standards allow. In the present case, we considered the level of performance assumed in establishing the MACT standard for purposes of determining whether the MACT standard provides an ample margin of safety. However, we did recognize that facilities were experiencing performance issues with flares and that many flares were not meeting the assumed performance level at the time we promulgated the MACT standard. Thus, we proposed, and are finalizing, revisions to the flare operating requirements to ensure that the flares meet the required performance level. These provisions are consistent with the EPA's goals to improve the effectiveness of our rules.
Similarly, we do not include startup, shutdown (including maintenance events) and malfunction emissions that are not allowed under the standard as part of our evaluation of whether the standards provide an ample margin of safety. Regarding the HAP emissions from SSM events that the commenter is concerned with, we note that our review of the TCEQ incident database indicates that many of the large reported release events were of SO
Because in the final rule we are establishing work practice standards for PRD and emergency flaring events, we performed a screening-level risk analysis to address changes in facility HAP emission releases due to these events. Details on this analysis are presented in the final risk report for the source category (For more details see Appendix 13 of the “Final Residual Risk Assessment for the Petroleum Refining Source Sector,” Docket ID No. EPA-HQ-OAR-2010-0682).
As for HAP with no reference value, the SAB addressed this issue in its May 7, 2010, response to the EPA Administrator. In that response, the SAB Panel recommended that, for HAP that do not have dose-response values from the EPA's list, the EPA should consider and use, as appropriate, additional sources for such values that have undergone adequate and rigorous scientific peer review. The SAB panel further recommended that the inclusion of additional sources of dose-response values into the EPA's list should be adequately documented in a transparent manner in any residual risk assessment case study. We agree with this approach and have considered other sources of dose-response data when conducting our risk determinations under RTR. However, in some instances no sources of information beyond the EPA's list are available. Compounds without health benchmarks are typically those without significant health effects compared to compounds with health benchmarks, and in such cases we assume these compounds will have a negligible contribution to the overall health risks from the source category. A tabular summary of HAPs that have dose response values for which an exposure assessment was conducted is presented in Table 3.1-1 of the “Final Residual Risk Assessment for the Petroleum Refining Source Sector”, Docket ID No. EPA-HQ-OAR-2010-0682.
As described in section IV.A.2 of this preamble, we performed a screening-level analysis to assess the risks associated with inventory updates we received for specific facilities and with emissions events that were previously not included in the risk assessment because the proposed rule did not allow them. Because we are finalizing work practice standards to regulate emission events associated with PRD releases and emergency flaring, we considered the effect these work practice standards would have on risks. As discussed in section IV.A.2 of this preamble, we project that accounting for these emergency events in the baseline risks after implementation of the MACT standards does not appreciably change the risks, and at most, could increase the proposed rule estimate of MIR by approximately 2-in-1 million. Therefore, we would project that any controls applied to these emergency events, including the work practice standards for PRDs and emergency flaring in this final rule, would not appreciably change the proposed post-control risks. Although we would anticipate minimal additional risk reductions, we reviewed more stringent alternatives to the work practice standards for PRD releases and emergency flaring events included in this final rule, and we found that the costs of increasing flare capacity to control all PRD releases and to eliminate all visible emissions during emergency flaring were too high. We estimate the capital costs of applying the velocity and visible emissions limit at all times would be approximately $3 billion, and we estimate that the costs of controlling all PRD releases with flares would be approximately $300 million. [See the discussion in the “Flare Control Option Impacts for Final Refinery Sector Rule”, Docket ID No. EPA-HQ-OAR-2010-0682 and the PRD work practice standard discussion in section IV.C of this preamble.] Further, we did not receive comments on additional control technologies that we should have considered for other emission sources (
The results of our technology review for the Petroleum Refinery source categories were published in the June 30, 2014, proposal at (79 FR 36913 through 36928). The technology review was conducted for both MACT source categories as described below.
Refinery MACT 1 sources include MPV, storage vessels, equipment leaks, gasoline loading racks, marine vessel loading operations, cooling towers/heat exchange systems and wastewater. Based on technology reviews for the sources described above, we proposed that it was not necessary to revise Refinery MACT 1 requirements for MPV, gasoline loading racks, cooling towers/heat exchange systems, and wastewater. For storage vessels, we proposed revisions pursuant to the technology review. Specifically, we proposed to cross-reference the storage vessel requirements in the Generic MACT (40 CFR part 63, subpart WW) to require controls on floating roof fittings (
We also proposed an additional work practice standard under the technology review to manage fugitive emissions from the entire petroleum refinery through a fenceline monitoring and corrective action standard. As part of the work practice standard, we specified the monitoring technology and approach that must be used, and we developed a fenceline benzene concentration action level above which refinery owners or operators would be required to implement corrective action to reduce their fenceline concentration to below this action level. The action level we proposed was consistent with the emissions projected from fugitive sources compliant with the provisions of the refinery MACT standards as modified by the additional controls proposed for storage vessels.
The Refinery MACT 2 source category regulates HAP emissions from FCCU, CRU and SRU process vents. We
At proposal, we did not identify any developments in practices, processes and control technologies for CRU process vents based on our technology review. For SRU, we proposed to include the Refinery NSPS subpart Ja allowance for oxygen-enriched air as a development in practice and to allow SRU to comply with Refinery NSPS subpart Ja as a means of complying with Refinery MACT 2.
We are finalizing most of our technology review decisions for Refinery MACT 1 emissions sources as proposed; however, as described briefly below, we are revising certain proposed requirements.
We are not taking final action adopting the use of appendix K to 40 CFR part 60 for optical gas imaging for refinery equipment subject to the LDAR requirements in Refinery MACT 1 because we have not yet proposed appendix K.
After considering the public comments, we are finalizing the proposed fenceline monitoring requirements, with a few revisions. First, we have made numerous clarifications in this final rule to the language for the fenceline monitoring siting method and analytical method (
We are finalizing, as proposed, our determination that it is not necessary to revise the requirements for CRU pursuant to the technology review and we are finalizing our determination that it is necessary to revise the MACT for SRU and FCCU. For SRU, we are finalizing the revisions as proposed. For FCCU, we are making modifications to the proposed requirements in light of public comment.
As discussed previously, we proposed to remove the alternative in Refinery MACT 2 for owners or operators to demonstrate compliance with the PM limits on FCCU by meeting a 30-percent opacity standard as provided in Refinery NSPS subpart J and instead make the FCCU operating limits in Refinery MACT 2 consistent with Refinery NSPS subpart Ja. Based on the Refinery NSPS subpart J review in 2008, we determined that a 30-percent opacity limit does not adequately assure compliance with the PM emissions limit (see discussion in the proposed rule at 79 FR 36929, June 30, 2014). Thus, we included other monitoring approaches in Refinery NSPS subpart Ja.
Comments received on this proposal, along with data available to the Agency, confirmed that the 30-percent opacity standard is not adequate on its own to demonstrate compliance with the PM (or metal HAP) emissions limit in Refinery MACT 2. We also received comments that the site-specific opacity alternative, which is the only compliance option proposed for FCCU with tertiary cyclones, would essentially require owners or operators with these FCCU configurations to meet an opacity limit of 10-percent. According to commenters, opacity increases with decreasing particle size, so that it is common to exceed 10-percent opacity during soot blowing or other similar events that produce very fine particulates even though mass emissions have not changed appreciably.
Based on the available data, we have determined that a 20-percent opacity operating limit is well correlated with
We are finalizing our proposed requirement that compliance with the control device operating limits in the other compliance alternatives be demonstrated on a 3-hour basis, instead of the 24-hour basis currently allowed in Refinery MACT 2.
The majority of comments received regarding the proposed amendments to Refinery MACT 1 pursuant to our technology review dealt with the proposed fenceline monitoring requirements. The primary comments on the fenceline monitoring requirements are in this section along with our responses. Comment summaries and the EPA's responses for additional issues raised regarding the proposed requirements resulting from our technology review are in the “Response to Comment” document in the public docket (Docket ID No. EPA-HQ-OAR-2010-0682).
Furthermore, we disagree that the fact that refiners are required to perform corrective action if the fenceline benzene concentration action level is exceeded makes the benzene action level an ambient standard. As an initial matter sources are not directly responsible for demonstrating that an area is meeting an ambient standard; rather that burden falls on states. See
We note that the sources addressed by the fenceline monitoring standard—refinery fugitive emissions sources such as wastewater collection and treatment
As an initial matter, we disagree with the commenters' characterization of the fenceline monitoring standard as “an information gathering and reporting obligation.” We have repeatedly stated that we consider the fenceline monitoring requirement to be a work practice standard that will ensure sources take corrective action if monitored benzene levels (as a surrogate for HAP emissions from fugitive emissions sources) exceed the fenceline benzene concentration action level. The standard requires refinery owners or operators to monitor the benzene concentration at the refinery perimeter, to evaluate the refinery's contribution as estimated by taking the concentration difference between the highest and lowest concentrations (ΔC) in each period, and to conduct root cause analysis and take corrective action to minimize emissions if the concentration difference is higher (on an annual average) than the benzene concentration action level. Thus, the fenceline monitoring requirement goes well beyond “information gathering and reporting.”
In addition, the commenters again read section 112(d)(6) too narrowly by suggesting that a program considered as a development must be a “technology” improvement. Section 112(d)(6) of the CAA requires the EPA to review and revise the MACT standards, as necessary, taking into account developments in “practices, processes and control technologies.” Consistent with our long-standing practice for the technology review of MACT standards, in section III.C of the proposal (see 79 FR 36900, June 30, 2014), we list five types of “developments” we consider. Fenceline monitoring fits squarely within two of those five types of developments (emphasis added):
• Any add-on control technology or other equipment that was not identified and considered during development of the original MACT standards.
• Any work practice or operational procedure that was not identified or considered during development of the original MACT standards.
As used here, “other equipment” is clearly separate from and in addition to “add-on control” technology and is broad enough to include monitoring equipment. In this case, fenceline monitoring is a type of equipment that we did not identify and consider during development of the original MACT standards. Additionally, the fenceline standard is a work practice standard, involving monitoring, root cause analysis and corrective action not identified at the time of the original MACT standards. Therefore, the fenceline requirements are a development in practices that will improve how facilities manage fugitive emissions and EPA appropriately relied on section 112(d)(6) in requiring this standard.
This regulatory approach also fits with the EPA's goals to improve the effectiveness of rules. Specifically, in this case, we are improving the effectiveness of the rule in two ways. First, we are establishing a fenceline benzene trigger to manage overall fugitive HAP emissions, rather than establishing further requirements on many individual emission points. Secondly, the rule incentivizes facilities to reduce fugitive HAP emissions below the fenceline benzene trigger by providing regulatory options for reduced monitoring.
Regarding ambient monitoring data, we note that existing ambient monitors are not located at the fenceline; they are located away from sources, and concentrations typically decrease exponentially with distance from the emissions source. We are encouraged that data referenced by the commenter indicate that ambient levels of benzene are within levels that are protective of human health in communities, but note that analysis of benzene concentrations in communities does not necessarily indicate that refineries located near these communities are adequately managing their fugitive HAP emissions.
We note that the existing MACT requirements are based on the MACT floor (the best performers), and as such, provide a significant degree of emission reductions from the baseline. The action level for the fenceline work practice standard, by contrast, is not based on the best performers but rather on the highest value expected on the fenceline from any refinery, based on the modeling of refinery emission inventories. As such it is not representative of the best performers and could not be justified as meeting the requirements of section 112(d)(2)and (3). If we were to remove the existing standards for fugitive emission sources at the refinery, we would not be able to justify that sources are meeting the level of control we identified as the MACT floor when we first promulgated the MACT. Nor could we justify the fenceline monitoring program we are promulgating as representing the MACT floor because we considered cost (and not the best performers as previously noted) in identifying the components of the program. Although the fenceline monitoring standard on its own cannot be justified as meeting the MACT floor requirement for each of the separate
The commenters also stated that the benefits of real-time monitors are particularly important in communities close to refineries, where they believe refinery emissions are a major source of toxic pollutants and short-term upset events that can have significant public health impacts. In particular, the commenters stated that open-path monitors promote an individual's right-to-know, in real-time, about harmful pollution events affecting their communities, and will allow refinery owners or operators to immediately identify fugitive emissions and undertake swift corrective action to reduce these emissions. Some commenters suggested that, if the EPA rejects these open-path real-time monitors, then at a minimum the EPA should require the use of active daily monitoring, such as auto-gas chromatograph (GC) systems.
Finally, a number of commenters recommended that the EPA provide sufficient flexibility in its regulations to allow state and local jurisdictions to develop, demonstrate, and subsequently require the use of alternative monitoring programs, provided these monitoring programs are at least equivalent to those in the final rule.
Both open-path systems and active sampling systems (such as auto-GCs) mentioned by the commenters, are monitoring systems capable of yielding monitoring data quickly—ranging from a few minutes to about a day. However, these “real-time” systems have not been demonstrated to be able to achieve all of the goals stated by the commenters—specifically, able to provide real-time analysis and data on multiple pollutants simultaneously at low-, near-ambient concentrations, with more complete geographic (or spatial) coverage of the fenceline.
The real-time open-path systems suggested by the commenters are all limited in that they are not sensitive enough to detect benzene at the levels needed to ensure that fenceline monitoring achieves its intended goal. The fenceline monitoring system needs to be capable of measuring at sub-ppbv levels—well below the 9 μg/m
For the final rule, we also reviewed other UV-DOAS systems in operation at refineries that commenters identified. However, reported detection limits for these systems are even higher than for the type of system being installed at Shell Deer Park. For example, we reviewed the open-path UV-DOAS system information from BP Whiting and found that they were able to verify a detection limit of 8 ppbv path average concentration for benzene over a 1,500-meter optical path. This is well above the 2.8 ppbv fenceline benzene concentration action level, let alone the sub-ppbv levels necessary to determine the ΔC. Moreover, this system, though commercially available, was optimized by developing alternative software to improve the detection limit (see memorandum “Meeting Minutes for April 21, 2015, Meeting Between the U.S. EPA and BP Whiting” in Docket ID No. EPA-HQ-OAR-2010-0682). Thus, the system, as installed, would not be readily available to other refineries. We reviewed data for the UV-DOAS system at the Chevron Richmond refinery and found that this system, with optical path lengths ranging from 500 to 1,000 meters, has a reported benzene detection limit of 5 ppbv averaged over the path length. Again, this is above the fenceline benzene concentration action level at the fenceline established in this final rule. In addition, we could not find any information to support the reported detection limit. We note that the public Web site operated by the City of Richmond, California indicates that information provided by the system is informational only, not quality assured, and not to be used for emergency response or health purposes.
We also disagree with the commenter's claim that if the EPA does not finalize requirements for real-time open-path monitors then, at a minimum, the EPA should require active daily monitoring. There are two methods of
To date, there are no commercially-available, real-time open-path monitors capable of detecting benzene at the sub-ppbv levels necessary to demonstrate compliance with the fenceline requirements in this final rule. Only a system that can detect such levels will result in effective action by facilities to identify and control fugitive emissions in excess of those contemplated by the MACT standards. Further, active monitoring systems, while potentially capable of detecting benzene at sub-ppbv levels, like open-path systems, become very costly when enough monitors are located around the facility to approach the spatial coverage of the passive diffusive tubes. However, we believe that the state of technology is advancing and that the capabilities of these systems will continue to improve and that the costs will likely decrease. If a refinery owner or operator can demonstrate that a particular technology would be able to comply with the fenceline standards, the owner or operator can request the use of an alternative test method under the provisions of 40 CFR 63.7(f). A discussion of the specific requirements for these requests can be found in the first comment and response summary of Chapter 8.3 of the “Response to Comment” document.
Several commenters noted that monitoring is limited to benzene as opposed to multiple HAP. One commenter noted that ill health experienced by refinery neighbors is due in large part to the synergistic effects of multiple chemicals. Therefore, the commenter stated that it is essential that the rule require monitoring of the full range of chemicals with health implications. Other commenters recommended that the fenceline monitoring requirement be amended to include additional contaminants, such as VOC, that may negatively impact human health and the environment. Conversely, other commenters stated that the EPA has appropriately selected benzene as a target analyte and surrogate for HAP emissions from petroleum refineries, as benzene is a common constituent in refinery feedstocks and numerous refinery streams, and is present in most HAP-containing streams in a refinery.
Petroleum refining emissions can contain hundreds of different compounds, including many different HAP, and no single method can detect every HAP potentially emitted from refineries. While several HAP are amenable to quantification via passive diffusive tube monitoring using the same adsorbent tubes used for benzene (
Two commenters argued for a lower action level threshold, citing the proposed California OEHHA rule, which finalized new and revised benzene reference exposure levels (REL) that are more stringent than the ones the EPA used in the residual risk assessment supporting the proposed rule.
Two commenters stated that while the fenceline benzene concentration action level of 9 μg/m
Several commenters stated that the EPA's 9 μg/m
On the other hand, several commenters opposed the 9 μg/m
Several commenters recommended action levels ranging from 15 μg/m
We disagree with the commenters that suggest that the proposed action level of 9 μg/m
We expect that the fenceline monitoring standard will result in improved fugitive HAP emissions management as it will alert the refinery owners or operators of fugitive sources releasing high levels of HAPs, such as large leaks, faulty tank seals, etc.
One commenter stated the proposed fenceline benzene concentration action level is effectively an ambient air standard, because corrective action to achieve that level is required and that if a facility's initial corrective action is unsuccessful, the rule provides that further action is required and the EPA must approve that further corrective action plan. Thus, the commenter argued, the EPA would essentially be able to dictate corrective actions, with no bounds on what could be required and no consideration of whether any cost-effective actions are available to assure the action level is met. The commenter continued that such a requirement converts a work practice program to an emission limitation and such ambient air limits are not authorized by CAA section 112. Several commenters noted that LDAR and current work practice programs have no similar requirement for the EPA approval, and the commenters suggested that the requirement for the EPA approval of any second corrective action should not be included in 40 CFR 63.658(h).
Another commenter recommended that, if after corrective action, a facility still has an exceedance for the next sampling episode,
We disagree with the claim that the EPA must assess the costs associated with the root cause analysis/corrective action requirements and establish a cost effectiveness threshold for any required root cause analysis/corrective action to ensure that limited resources are effectively and efficiently applied for the control of emissions. We did not attempt to project the costs of the root cause analysis/corrective action for at least two reasons. First, based on the dispersion modeling of the benzene emissions reported in response to the inventory section of the 2011 ICR, we project that no refinery should exceed that fenceline benzene concentration action level if in full compliance with the MACT standards, as amended by this action. Thus, assuming compliance with the MACT standards, we would expect that there are no costs for root cause analysis/corrective action. To the extent that there are exceedances of the action level, the premise of the fenceline monitoring is to provide the refinery owners or operators with the flexibility to identify the most efficient approaches to reduce the emissions that are impacting the fenceline level. Since the choice of control is a very site-specific decision, we would have no way to know how to estimate the costs. Thus, the source is in the best position to ensure that resources are effectively and efficiently spent to address any exceedance.
We intended the proposed requirement for refinery owners or operators to submit a corrective action plan for the EPA approval to provide the Administrator with information that they were making a good-faith effort to reduce emissions below the fenceline benzene concentration action level, as expeditiously as practicable. However, we understand the importance for refinery owners or operators to begin corrective action as soon as possible, without having to wait for the EPA approval. Therefore, we are finalizing the requirement for refinery owners or operators to submit such plans but we are not finalizing the requirement that the EPA must approve the plan prior to the corrective action being taken.
We previously responded to comments regarding UV-DOAS or other open-path monitoring systems in this section, explaining that the current detection limits for these systems exceeds the action level threshold and, thus, these systems would not provide usable data to inform corrective action. Thus, we disagree that the EPA should require these systems for all facilities whose first attempt at corrective action is ineffective.
Numerous commenters requested that the rule clarify where monitors need to be placed in special circumstance, such as refineries bisected by a road, railroad or other public right-of-way or a boundary next to a navigable waterway. Several commenters stated that refiners should not need to place monitors on these property boundaries or other property boundaries where there are no residences within 500 feet of the property line. Commenters also asked if areas that had non-refinery operations, but are still inside the property boundary, would be included for purposes of determining where to site monitors.
A few commenters expressed concern about the approach for determining the number of required monitors at a site based on the acreage, noting that it is unfair to small facilities and will leave gaps in monitoring coverage for very large facilities. Some commenters recommended amending the proposed rule to require the placement of fenceline monitors at fixed distances along facilities' perimeters with no maximum number of monitors. Some commenters stated that the rule should specify an acceptable range on the 2,000-foot spacing requirement or the radial placement requirement as it may be necessary to address accessibility or safety concerns. Several commenters suggested that a lower minimum number of sampling monitors should be required for very small refineries or small “subareas.” These commenters noted that refineries often include disconnected parcels that can be very small (
We intended that the fenceline monitoring would create a monitoring perimeter capable of detecting emissions from all fugitive emission sources at the refinery facility. We have long established that a road or other right of way that bisects a plant site does not make the plant site two separate facilities, and, thus, would not be considered part of the property boundary. As we agree that monitors need only be placed around the property boundary of the facility, it would not be necessary to place monitors along a road or other right-of-way that bisects a facility. We have clarified this in the final rule and Method 325A.
If the facility is bounded by a waterway on one or more sides, then the shoreline is the facility boundary and monitors should be placed along this boundary. If the waterway bisects the facility, the waterway would be considered internal to the facility and monitors would only be needed at the facility perimeter.
Regarding the comment that monitors should not be required where there is no residence within 500 feet of the property line, we disagree. We proposed and are finalizing the fenceline monitoring standards under CAA section 112(d)(6) as a means to improve fugitive HAP emissions management, regardless of whether there are people living near a given boundary of the facility.
Regarding the clarification requested about monitor placement considering non-refinery operations, the property boundary monitors should be placed outside of all sources at the refinery. This is because moving the monitoring line inward to exclude the non-refinery source could lead to an underestimation of the ΔC compared to the monitoring external of the entire site. If the non-refinery source is suspected of contributing significantly to the maximum concentration measured at the fenceline, a site-specific monitoring plan and monitoring location specific near-field interfering source (NFS) corrections will be needed to address this situation.
Section 8.2.3 of Method 325A includes language to provide some flexibility when using the linear placement (±10% or ±250 feet). We consider it reasonable to provide similar placement allowance criteria for the radial placement option (±1 degree). We are not providing requirements that would allow small area refineries to use fewer than 12 monitoring sites. We do not consider that any refinery would be so small as to warrant fewer than 12 monitors; however, we did not necessarily consider very small subareas for irregularly shaped facilities or segregated operations. When considering these subareas, we agree that fewer than 12 monitoring sites should be appropriate. Therefore, we have provided that monitors do not need to be placed closer than 152 meters (500 feet) (or 76 meters (250 feet) if known sources are within 50 meters (162 feet) of the monitoring perimeter, which is likely for these subareas or segregated areas) with a stipulation that a minimum of 3 monitoring locations be used per subarea or segregated area. We note, however, that this distance provision does not obviate the near source extra monitoring siting requirements or the requirement to have a minimum of three monitors per subarea or segregated area.
If facility owners or operators have questions regarding the required locations of monitors for a specific application, they should contact the EPA (or designated authority) to resolve questions about acceptable monitoring placement.
Other commenters disagreed with the EPA's proposed compliance time and suggested that the EPA shorten the timeline for implementation at refineries so that possible corrective action occurs much sooner than proposed. The commenters suggested that deployment of passive samplers can proceed more promptly than proposed, especially since the EPA has simultaneously proposed specific “monitor siting and sample collection requirements as EPA method 325A of 40 CFR part 63, Appendix A, and specific methods analyzing the sorbent tube samples as EPA Method 325B of 40 CFR part 63, Appendix A.” Moreover, the commenter noted, a principal reason that the EPA selected passive monitors over active monitors was due to the relative “ease of deployment.” The commenter claimed this ease of deployment rationale is undermined by a 3-year grace period to deploy passive monitors when the EPA is providing very specific criteria for their use. The commenter suggested that the EPA require full compliance with the passive monitoring requirement within 1 year of the effective date of the rule.
Commenters also stated that the EPA should adopt reporting requirements to ensure that facilities report the monitoring data appropriately. Specifically, commenters recommended that 40 CFR 63.655(h)(8)(i) should be clarified to only require reporting of valid data and cautioned that data should be processed to allow accurate calculations of annual averages to be used for reporting and evaluation. To accomplish this, commenters recommended that the rule provide 75 days from the end of a 6-month sampling period to report to the EPA, rather than the proposed 45-day period, in order to provide adequate time to obtain quality-assured results for all 2-week sampling periods.
One commenter applauded the proposal's requirements for electronic reporting of the fenceline concentration data and making the resulting information publicly available. However, the commenter recommended that the EPA consider a more truncated data reporting period that is more consistent with the associated milestones of collecting a 14-day sampling episode. As is, the commenter claimed, the proposed rule would have a lag time of up to 7.5 months between data collection and posting. The commenter indicated that data reporting on a more frequent schedule will not only provide transparency, but will provide states and local agencies with information about air quality at refineries at a frequency that could allow informed activities to address leaks much more quickly and protect public health.
Regarding commenters' concerns that facilities post accurate data and have sufficient time to perform quality assurance on the data, in the final rule, we have established provisions for how sources are to address outliers and data corrections. Additionally, as proposed, we do not require an initial report until facilities have collected 1 year of data so that facilities do not report the data until a rolling annual average value can be determined. This will allow refinery staff and analytical laboratories to iron out any issues that might arise as they implement these methods for the first time. Once this initial data collection period is complete, we anticipate that data quality issues should be infrequent. Therefore, we are providing a 45-day period following each quarterly period before facilities must submit the monitoring results, which should provide facilities adequate time to correct any data errors prior to reporting the data.
Regarding comments that suggest reporting each 2-week sample result soon after its collection, we disagree. This frequency would put undue burden on the refinery owners or operators in trying to collect, review and quality assure the data prior to reporting. However, we agree with commenters that more frequent reporting of the fenceline monitoring data would be useful. Therefore, we have revised the reporting frequency for the fenceline monitoring data to be quarterly in the final rule rather than semiannually as proposed. Additionally, we understand that there is a lot of interest in how these data will be presented to the public, and we plan to reach out to all stakeholders on appropriate approaches for presenting this information in ways that are helpful and informative.
This section provides comment and responses for the key comments received regarding the technology review amendments proposed for Refinery MACT 2. Comment summaries and the EPA's responses for additional issues raised regarding the proposed requirements resulting from our technology review are in the “Response to Comment” document in the public docket (Docket ID No. EPA-HQ-OAR-2010-0682).
We received comments on the consideration of developments in pollution controls, the averaging time for FCCU PM limits, and the FCCU opacity limit, as discussed below.
Second, the commenter claimed that the EPA's review of developments is nearly 10 years old and misses some important pollution control
The commenter also asserted that EPA consent decrees impose lower effective limits on PM than the EPA considered under the technology review. The commenter identified the BP Whiting facility as subject to 0.7 lb PM/1,000 lbs coke burn-off at one FCCU and 0.9 lb PM/1,000 lbs coke burn-off at another and claimed these limits are lower than the 1.0 lb PM/1,000 lbs coke burn-off limit currently mandated by Refinery MACT 2.
Regarding the claim that the EPA did not consider the types of controls at the Valero and BP facilities, we disagree. The control measures for both of those facilities are controls that existed at the time of the development of the MACT standard. Thus, we did not identify these technologies as developments in control technologies during the technology review. However, we did identify developments in processes or practices that reflect better control by the existing technology and we reviewed modified emission limits that reflect that better level of control. The commenter suggested that we failed to consider a level of zero when the Valero facility was able to achieve zero emissions through a combined SCR, boiler and scrubber. However, the commenter provided no information to support such a claim and we are skeptical that such a result could be achieved. We note that the SCR is designed specifically to reduce NO
The commenters also state that the EPA's additional arguments for the change to a 3-hour average are irrelevant and legally deficient. The commenters stated that the combination of a numerical emission limit and an averaging period frames the stringency of a limitation and that a reduction in either of those factors results in a significant lowering of the operating limit. The commenters conclude that the EPA has proposed to change the stringency of the requirements without justification, and the CAA requires that such a change in stringency be justified pursuant to CAA section 112(d)(6) or (f)(2). The commenters stated that increasing stringency for consistency with NSPS rules is not a criterion for a CAA section 112(d)(6) action. Rather that section requires a change to be due to “developments.” The only change in technology since the 2002 promulgation of Refinery MACT 2 is the availability of PM continuous emission monitoring system (CEMS), which is unproven.
One commenter noted that changing the averaging time is a very significant modification considering that the compliance limits would apply for periods of SSM. This commenter stated that it is unlikely that existing operations can consistently be in compliance with a new 3-hour average since the current daily averaging was put in place to recognize that there will be periods of operating variability that do not represent the longer term performance of an FCCU. The commenters recommended that the EPA retain the daily averaging requirement.
However, whether or not it is a change from the MACT floor is not relevant. Pursuant to CAA section 112(d)(6), the EPA must revise MACT standards “as necessary” considering developments in practices, processes and control technologies. For this
• Any add-on control technology or other equipment that was not identified and considered during development of the original MACT standards.
• Any improvements in add-on control technology or other equipment (that were identified and considered during development of the original MACT standards) that could result in additional emissions reduction.
• Any work practice or operational procedure that was not identified or considered during development of the original MACT standards.
• Any process change or pollution prevention alternative that could be broadly applied to the industry and that was not identified or considered during development of the original MACT standards.
• Any significant changes in the cost (including cost effectiveness) of applying controls (including controls the EPA considered during the development of the original MACT standards).
In determining whether there are “developments,” we review, among other things, EPA regulations promulgated after adoption of the MACT, such as the NSPS we identified in this instance. We identified the enhanced monitoring requirements for these operating limits as a development in practices that will help ensure FCCU owners or operators are properly operating control devices and, thus, are meeting the PM emission limit at all times. We further determined that this enhanced monitoring was cost effective and proposed that it was necessary to revise the existing standard pursuant to CAA section 112(d)(6).
While we do not have continuous PM emissions data that show actual deviations of the PM limit, we do not need such data in order to conclude that such deviations could occur when daily averages are used. The Refinery MACT 2 (
Several commenters urged the EPA to maintain the 30-percent opacity limit for these FCCUs. As a practicable and cost-effective alternative to address the EPA's concern as to whether compliance with a 30-percent opacity limit ensures compliance with the PM emissions limit, commenters suggested annual performance tests to confirm that the FCCU is meeting the PM emissions limit, rather than performance tests every 5 years, as proposed.
One commenter stated that the EPA never intended for the opacity limit in Refinery NSPS subpart J to be used to demonstrate compliance with the PM emissions limit, but instead to assure the PM controls operate properly. The commenter stated that the EPA's conclusion that the 30-percent opacity limit may not be sufficiently stringent to ensure compliance with the underlying PM emissions limit is based on a false premise as to the purpose of the opacity standard because as the EPA states, “Opacity of emissions is indicative of whether control equipment is properly maintained and operated.”
Several commenters stated that the proposed elimination of the 30-percent opacity limit currently in Refinery MACT 2 leaves existing FCCUs that use cyclones with no viable alternative approach to demonstrate compliance with the PM emissions limit without adding or replacing controls. They stated the other approaches for demonstrating compliance with the PM emissions limit in Refinery MACT 2 (such as development of a site-specific opacity limit) do not work for them. The commenters stated that although they believe that more frequent performance tests would show that the FCCUs are in fact meeting the PM emissions limit, the absence of the 30-percent opacity limit would force FCCUs using cyclones for PM control to install additional, costly PM controls (
While the compliance study indicates that a 30-percent opacity limit does not correlate well with a 1.0 lb PM/1,000 lbs coke burn-off emissions limit, further review of this same study indicates that a 20-percent opacity limit provides a reasonable correlation with units meeting the 1.0 lb PM/1,000 lbs coke burn-off emissions limit. We also reviewed the data submitted by the commenters regarding PM emissions and opacity correlation. While the data suggest that there is variability and uncertainty in the PM/opacity correlation, the data do not support that a 30-percent opacity limit would ensure compliance even when considering the uncertainty associated with the PM/opacity correlation. Based on the variability of the 3-run average opacity limits, we determined that, if the 3-hour average opacity exceeded 20-percent, then it was highly likely (98 to 99-percent confidence) that the FCCU emissions from the unit tested would exceed the PM emissions limit.
After considering the public comments, reviewing the data submitted with those comments, and further review of the compliance study, in this final rule we are adding a 20-percent opacity limit, evaluated on a 3-hour average basis for units subject to NSPS subpart J. As we noted above, a 20-percent opacity limit provides a reasonable correlation with the PM emissions limit, and an exceedance of this 20-percent opacity limit will provide evidence that the PM emissions limit is exceeded. However, it is possible that units could still exceed the PM emissions limit while complying with the 20-percent opacity limit, if those units operate close to the 1 lb PM/1,000 lbs coke burn-off emissions limit. To address this concern, we considered the commenters' suggestion to require a performance test annually rather than once every 5 years. Some commenters suggested that this option specifically apply to FCCUs with cyclones, but this option is applicable to any control system operating very near the PM emissions limit and using an opacity limit to demonstrate continuous compliance. We have determined that the Refinery NSPS subpart J compliance procedures in Refinery MACT 2, in combination with a 20-percent opacity limit demonstrated on a 3-hour average basis and with annual performance tests when a test indicates PM emissions are greater than 80-percent of the limit (
We do not agree with commenters that the proposed opacity revision would add significant cost or compliance burden. The control device-specific monitoring parameters that were proposed rely on parameters commonly used to control the operation of the control device, so the monitoring systems should be already available. Further, since we are merely changing the opacity limit, we expect these units will already have opacity monitoring systems needed to demonstrate compliance with the PM emissions limit and would not incur costs for new equipment.
In contrast, some commenters expressed concerns about high HCN levels. One commenter stated that the EPA should consider re-evaluating the benefit of low NO
One commenter stated that the EPA must set stronger HCN standards on FCCU emissions because of the high release amounts reported, the fact that non-cancer risk is driven by emissions of HCN from FCCU, and the fact that the EPA has never set standards for HCN emissions. The commenter provided a report that they believe shows that the EPA has not shown that CO is a reasonable or lawful surrogate to control HCN and has not shown that the conditions necessary for a surrogate are met with regard to CO and HCN, which is an inorganic nonmetallic HAP. Further, the report indicates that SCR is a reasonable and cost effective method for controlling HCN and that the EPA failed to review and consider other viable methods to control HCN and must do so to satisfy its legal obligations in this rulemaking.
In the current rulemaking action, we determined at the time of the proposed rule that this also holds true for HCN emissions. That is, once CO emissions are reduced to below 500 ppmv (
All of the HCN emissions data we have were reported from units operating at or below the 500 ppmv CO limit (
We initially thought the higher levels of HCN emissions that were reported by sources achieving complete combustion might be due to a switch away from platinum-based combustion promoters to palladium-based combustion promoters. However, many of the units that were tested and that had some of the lowest HCN emissions used palladium-based oxygen promoters. Therefore, it appears unlikely that palladium-based catalyst promoters are linked to the higher HCN emissions. We also evaluated one commenter's argument that CO is not a good surrogate for HCN emissions, but that SCR are a reasonable and cost-effective control strategy. We are not aware of any data that suggest that an SCR removes HCN and the commenter did not provide any support for that premise. At proposal, we evaluated HCN control on units using extra oxygen or converting back to platinum-based promoters to oxidize any HCN formed. This would cause more NO
For the purposes of Refinery MACT 2, we consider the emission limits and operating requirements for organic HAP in Tables 8 through 14 to subpart UUU of part 63 adequate to also limit HCN emissions.
Finally, we understand concerns about the reported HCN emissions being higher than anticipated and the need for more data to better determine HCN emissions levels. To address these concerns, we are finalizing a requirement that facility owners or operators conduct a performance test for HCN from all FCCU at the same time they conduct the first PM performance test on the FCCU following promulgation of this rule. Facility owners or operators that conducted a performance test for HCN from a FCCU in response to the refinery ICR or subsequent to the 2011 Petroleum Refinery ICR following appropriate methods are not required to retest that FCCU.
We did not receive substantive comments concerning our proposal that it was not necessary to revise Refinery MACT 1 requirements for MPV, gasoline loading racks and cooling towers/heat exchange systems. Based on the rationale provided in the preamble to the proposed rule, we are taking final action concluding that it is not necessary pursuant to CAA section 112(d)(6) to revise the MACT requirements for MPV, gasoline loading racks and cooling towers/heat exchange systems emission sources at refineries.
We proposed that the options for additional wastewater controls are not cost effective and thus it was not necessary to revise the MACT for these emission sources. We received public comments suggesting that emissions from wastewater systems are higher than modeled and that we should develop additional technology standards for wastewater treatment systems regardless of cost. As we discussed in the proposal, emissions from wastewater are difficult to measure and emission estimates rely on process data and empirical correlations, which introduces uncertainty into the estimates. Although we do not have evidence, based on the process data we collected, that emissions are higher than modeled at proposal, we note that the fenceline monitoring program effectively ensures that wastewater emissions are not significantly greater than those included in the emissions inventory and modeled in the risk assessment. Furthermore, we believe that cost is a valid consideration in determining whether it is necessary within the meaning of section 112(d)(6) to revise requirements and that we are not required to establish additional controls regardless of cost. Consequently, we conclude that it is not necessary to revise the Refinery MACT 1 requirements for wastewater systems pursuant to CAA section 112(d)(6).
For storage vessels, we identified a number of options, including requiring tank fitting controls for external and internal floating roof tanks, controlling smaller tanks with lower vapor pressures and requiring additional monitoring to prevent roof landings, liquid level overfills and to identify leaking vents as developments in practices, processes and control technology. We proposed to cross-reference the storage vessel requirements in the Generic MACT (effectively requiring additional control for tank roof fittings) and to revise the
For equipment leaks, we identified specific developments in practices, processes and control technologies that included requiring repair of leaking components at lower leak definitions, requiring monitoring of connectors, and allowing the use of the optical imaging camera as an alternative method of monitoring for leaks. We proposed to establish an alternative method for refineries to meet LDAR requirements in Refinery MACT 1. This alternative would allow refineries to monitor for leaks via optical gas imaging in place of EPA Method 21, using monitoring requirements to be specified in a not yet proposed appendix K to 40 CFR part 60. However, the development of appendix K is taking longer than anticipated. Therefore, we are not finalizing this alternative monitoring method in Refinery MACT 1.
We received comments suggesting that additional requirements be imposed to further reduce emissions from leaking equipment components, such as requiring “leakless” equipment, reducing the leak threshold, and eliminating delay of repair provisions. As provided in the “Response to Comments” document, we do not agree that these additional requirements are cost-effective. Based on the rationale provided in the preamble to the proposed rule and our consideration of public comments, we conclude that it is not necessary to revise the Refinery MACT 1 requirements for equipment leaks. Again, however, the fenceline monitoring program is intended to ensure that large leaks from fugitive emissions sources, including equipment leaks, are more quickly identified and repaired, thereby helping to reduce emissions from leaking equipment components.
For marine vessel loading, we identified control of marine vessel loading operations with HAP emissions of less than 10/25 tpy and the use of lean oil absorption systems as developments that we considered in the technology review. We proposed to amend 40 CFR part 63, subpart Y to require small marine vessel loading operations (
Finally, we proposed that it was necessary to revise the MACT to require fenceline monitoring as a means to manage fugitive emissions from the entire petroleum refinery, which includes sources such as wastewater collection and treatment operations, equipment leaks and storage vessels. We received numerous comments regarding the proposed requirement to conduct fenceline monitoring, many of which we address above and the remainder of which we respond to in the “Response to Comments” document. After considering comments, we maintain that the proposed work practice standard is authorized under section 112 of the CAA and will improve fugitive management at the refinery. Therefore, we are finalizing the key components of fenceline monitoring work practice as proposed. These requirements include the use of passive diffusive tube samplers (although we are providing a mechanism to request approval for alternative monitoring systems provided certain criteria are met), the 9 μg/m
Based on public comments received, we are making numerous revisions to clarify the fenceline monitor siting requirements. This includes provisions to allow siting of monitors within the property boundary as long as all emissions sources at the refinery are included within the monitoring perimeter. We are also clarifying that we do not consider public roads or public waterways that bisect a refinery to be property boundaries, and owners or operators do not need to place monitors along the internal public right-of-ways. We are also providing provisions to allow fixed placement of monitors at 500 feet intervals (with a minimum of 3 monitors) for subareas or segregated areas. If an emissions source is near the monitoring perimeter, an additional monitor siting requirement would still apply. The 500 feet provision is provided to reduce burden for facilities with irregular shapes or noncontiguous property areas that we did not fully consider at proposal.
We also received comments on the compliance time and reporting requirements associated with the fenceline monitoring provisions. Upon consideration of public comments, we have revised the compliance period to 2 years after the effective date of the final rule. Thus, beginning no later than 2 years after the effective date of the rule, the source must have a fenceline monitoring system that is collecting samples such that the first rolling annual average ΔC value would be completed no later than 3 years after the effective date of the final rule. Facilities will have 45 days after the completion of the first year of sampling, as proposed, to submit the initial data set. We are reducing the proposed compliance period from 3 years to 2 years because the passive diffusive tube monitors are easy to deploy and pilot study demonstrations indicate that significant time is not needed to deploy the monitors. However, the reduced compliance period still provides time to resolve site-specific monitor placement issues and to provide time to develop and implement a site-specific monitoring plan, if needed. We are increasing the fenceline monitoring reporting frequency (after the first year of data collection) from semiannually to quarterly to provide more timely dissemination of the data collected via this monitoring program.
We proposed to revise Refinery MACT 2 to incorporate the developments in monitoring practices and control technologies reflected in the Refinery NSPS subpart Ja limits and monitoring provisions (73 FR 35838, June 24, 2008). We are finalizing most of these provisions as proposed. Specifically, we are incorporating the
We also proposed to eliminate the Refinery NSPS subpart J compliance option that allows refineries to meet the 30-percent opacity emissions limit requirement and revise the MACT to include control device operating limits or site-specific opacity limits identical to those required in Refinery NSPS subpart Ja. We received numerous comments, particularly from owners or operators of FCCU that employ tertiary cyclones to control FCCU PM emissions. According to the commenters, opacity is not a direct indicator of PM emissions because finer particles will increase opacity readings without a corresponding mass increase in PM emissions. Additionally, the commenters stated that the site-specific opacity limit generally leads to a site-specific operating limit of 10-percent opacity, which is too stringent and does not adequately account for variability between PM emissions and opacity readings. According to the commenters, FCCU with tertiary cyclones would need to be retrofitted with expensive and costly controls in order to meet the 10-percent opacity limit, even though they are meeting the 1 lb/1000 lbs coke burn PM emissions limit. It was not our intent to require units to retrofit their controls simply to meet the site-specific opacity limit. However, the existing 30-percent opacity limit in the subpart J compliance option is not adequate to ensure compliance with the PM emissions limit at all times. After reviewing the public comments and available data, we determined that, rather than removing the subpart J compliance option altogether, it is sufficient to add an opacity operating limit of 20-percent opacity determined on a 3-hour average basis to the existing subpart J compliance option and to require units complying with this operating limit to conduct annual performance tests (rather than one every 5 years) when the PM emissions measured during the source test are greater than 0.80 lb PM/1,000 lbs coke burn-off. These provisions improve assurance that these units are, in fact, achieving the required PM emissions limitation without requiring units to retrofit controls due to variability in the correlation of PM emissions and opacity.
We did not propose to revise the organic HAP emissions limits for FCCU to further address HCN emissions. We received numerous comments on this issue. We continue to believe that complete combustion is the appropriate control needed to control HCN emissions. Consequently, for the purposes of Refinery MACT 2, we are not changing the MACT standards to further reduce emissions of HCN. However, we understand that there are uncertainties and high variability in HCN emissions measured from FCCU. In order to address the need for more data to better characterize HCN emissions levels, we are finalizing a requirement for refinery owners or operators to conduct a performance test for HCN from all FCCU (except those units that were tested previously using acceptable methods as outlined in the 2011 Refinery ICR) during the first PM test required as part of the on-going compliance requirements for FCCU metal HAP emissions. These data will be useful to the EPA in understanding HCN emissions from FCU and may help to inform future regulatory reviews for this source category.
We proposed that there have been no developments in practices, processes, and control technologies for CRU based on our technology review and that therefore it is not necessary to revise these standards. Based on the rationale provided in the preamble to the proposed rule and our consideration of public comments, we are finalizing our conclusion.
For SRU, we identified the Refinery NSPS subpart Ja allowance for oxygen-enriched air as a development in practice and we proposed that it was necessary to revise the MACT to allow SRU to comply with Refinery subpart Ja as a means of complying with Refinery MACT 2. The key issue identified by commenters was that Refinery NSPS subpart Ja includes a flow monitoring alternative for determining the average oxygen concentration in the enriched air stream and that this was not included in the proposed amendments to Refinery MACT 2. This was an oversight on our part. We are, based on the rationale provided in the preamble to the proposed rule and our consideration of public comments, finalizing the SRU revisions as proposed but with inclusion of the flow monitoring alternative provisions that are in Refinery NSPS subpart Ja for this source.
We proposed the following revisions to the Refinery MACT 1 and 2 standards pursuant to CAA section 112(d)(2) and (3)
For DCU, we proposed to require that prior to venting or draining, each coke drum must be depressured to a closed blowdown system until the coke drum vessel pressure is 2 psig or less. As proposed, the 2 psig limit would apply to each vessel opening/venting/draining event at new or existing affected DCU facilities.
For the CRU, we proposed to require that any emissions during the active
For flares, we proposed to remove cross references to the General Provisions requirements for flares used as control devices at 40 CFR 63.11(b) and to incorporate enhanced flare operational requirements directly into the Refinery MACT rules. The proposed rule amendments included:
• A ban on flaring of halogenated vent streams.
• A requirement to operate with continuously lit pilot flames at all times and to equip the pilot system with an automated device to relight the pilot if it is extinguished.
• A requirement to operate with no visible emissions except for periods not to exceed a total of 5 minutes during any 2 consecutive hours and to monitor for visible emissions daily.
• A requirement to operate with the flare tip velocity less than 60-feet-per-second or the velocity limit calculated by an equation provided in the proposed rule.
• A requirement to meet one of three combustion zone gas properties operating limits based on the net heating value, lower flammability limit, or combustion concentration. Owners or operators could elect to comply with any one of the three limits at any time. Two separate sets of operating limits were proposed: One for gas streams not meeting all three “hydrogen-olefin interaction criteria” specified in the rule and a more stringent set of limits for gas streams meeting all three hydrogen-olefin interaction criteria. The combustion zone net heating value considered steam assist rates but not “perimeter air” assist rates.
• For air-assisted flares, a requirement to meet an additional “dilution parameter” operating limit determined based on the combustion zone net heating values above, the diameter of the flare and the perimeter air assist rates.
The proposed amendments for flares also included detailed monitoring requirements to determine these operating parameters either through continuous parameter monitoring systems or grab sampling, detailed calculation instructions for determining these parameters on a 15-minute block average, and detailed recordkeeping and reporting requirements. We also proposed provisions to allow owners or operators to request alternative emissions limitations that would apply in place of the proposed operating limits.
We proposed to revise the definition of MPV to remove the current exclusion for in situ sampling systems (onstream analyzers). We also proposed to limit the exclusion for gaseous streams routed to a fuel gas system to apply only to those systems for which any flares receiving gas from the fuel gas system are in compliance with the proposed flare monitoring and operating limits. We note that we also proposed revisions related to monitoring of bypass lines, but these revisions were proposed to address concerns related to SSM releases and are described in further detail in section IV.D. of this preamble.
We proposed that emissions of HAP may not be discharged to the atmosphere from PRD in organic HAP service to address concerns related to SSM releases. To ensure compliance with this proposed amendment, we proposed to require that sources monitor PRD using a system that is capable of identifying and recording the time and duration of each pressure release and of notifying operators that a pressure release has occurred. This proposed requirement was addressed in section IV.A.4. of the preamble for the proposal.
We proposed identical standards for existing and new DCU decoking operations, but we are finalizing standards for new and existing sources that are not identical. We are finalizing provisions that will require owners or operators of existing DCU sources to comply with a 2 psig limit averaged over 60 cycles (
For flares, we are not finalizing the ban that we proposed on halogenated vent streams and we are not finalizing the proposed requirement to equip the flare pilot system with an automated device to relight an extinguished pilot.
We are revising the MACT to include the proposed no visible emissions limit and the flare tip velocity limit as direct emissions limits only when the flare vent gas flow rate is below the smokeless capacity of the flare. Under the revised standard, when the flare is operating above the smokeless capacity, an exceedance of the no visible emission limit and/or flare tip velocity limit is not a violation of the standard but instead triggers a work practice standard. Flares operate above the smokeless capacity only when there is an emergency release event and thus the work practice standard is intended to address emissions during such emergency release events. (See section IV.D. of this preamble for more details regarding this work practice standard). We are also adding provisions that would allow sources to use video surveillance of the flare as an alternative to daily Method 22 visible emissions observations.
For flares, we are also simplifying the combustion zone gas property operating limits by finalizing a requirement only for the net heating value of the combustion zone gas. We are finalizing requirements that flares meet a minimum operating limit of 270 BTU/scf NHVcz on a 15-minute average, as proposed, and we are allowing refinery owners or operators to use a corrected heat content of 1212 BTU/scf for hydrogen to demonstrate compliance with this operating limit. We are not finalizing separate combustion zone operating limits for gases meeting the hydrogen-olefin interaction criteria that were proposed. We are also not finalizing the alternative combustion zone operating limits based on lower flammability limit or combustibles concentration.
We are finalizing “dilution parameter” requirements for air-assisted flares, but we are providing a limit only for the net heating value dilution parameter. Similar to the requirements we are finalizing for the combustion zone parameters, we are finalizing requirements that flares meet a minimum operating limit of 22 BTU/ft
We are providing an alternative to use initial sampling period and process knowledge for flares in dedicated service as an alternative to continuous or on-going grab sample requirements for determining waste gas net heat content.
We are finalizing revisions to the definition of MPV, as proposed.
We are establishing work practice standards that apply to PRD releases in place of the proposed prohibition on PRD releases to the atmosphere. The work practice standards that we are finalizing for PRD require refiners to establish proactive, preventative measures for each PRD to identify and correct direct releases of HAP to the atmosphere as a result of pressure release events. Over time, these proactive measures will reduce the occurrence of releases and the magnitude of releases when they occur, while avoiding the environmental disbenefits of having additional flare capacity on standby to control these unpredictable and infrequent events. Refinery owners or operators will be required to perform a root cause analysis/corrective action following such pressure release events. In addition, a second release event in a 3-year period from the same PRD with the same root cause on the same equipment is a deviation of the work practice standard. A third release event in a3-year period from the same PRD is a deviation of the work practice standard regardless of the root cause. PRD release events related to force majeure events are not considered in these hard limits.
As discussed in response to the previous comment, we are basing the MACT floor for existing source DCU on responses we received from the 2011 Petroleum Refinery ICR. Because the ICR requested the “typical coke drum pressure when first vented to the atmosphere,” we do not consider the information provided in ICR responses to reflect a “never-to-be-exceeded” limit. Therefore, we evaluated whether it is reasonable to allow averaging, and if so, what averaging period should be provided.
Health risks are not considered in establishing MACT requirements, so we do not consider the argument that chronic effects are evaluated over a 70-year period to be relevant to a determination of the MACT floor. However, a primary consideration regarding averaging periods is how the averaging period was considered in setting the floor and whether the intended reductions will occur under a different averaging period. According to the heat balance method for estimating DCU emissions, DCU decoking operations emissions are directly proportional to the average bed temperature. While the relationship is not exactly linear, the average bed temperature is expected to be a function of the venting pressure. Moreover, the shape of the pressure-temperature correlation curve is such that the emissions at 6 psig are almost exactly but not quite three times the emissions at 2 psig. Given the expected linearity of the emissions with venting pressures, we are not concerned with an occasional venting event above 2 psig because the average emissions from a facility meeting an average 2 psig pressure limit would be identical to the emissions achieved by a facility that vented each time at 2 psig. That is, given the expected linearity in the projected DCU emissions to the venting pressure, we conclude that it is reasonable to allow averaging across events and that the precise averaging period is not a critical concern.
Most industry commenters requested a 30-day average. However, different facilities have different numbers of DCU, different numbers of drums per DCU and different cycle times. Consequently, basing the averaging period across a given time period would result in significantly different number of venting events included in a 30-day average for different facilities and generally provide more flexibility to larger refineries and less flexibility to smaller refineries. Based on the ICR responses, almost half of all DCU operate with two drums and about 90-percent of DCU have two to four coke drums; however, a few DCU have six or even eight drums. Also, based on the ICR responses, the average complete coke drum cycle time is 32 hours, but can be as short as 18 hours and as long as 48 hours. Reviewing the ICR responses, we found that a 30-day average would include 30 events for some facilities and more than 250 events at other facilities.
Since the existing source MACT standards apply “in combination” to “all releases associated with decoking operations” at a given facility, we determined that it was reasonable to consider an averaging period that applies to the number of venting events from all coke drums at the facility rather than to all coke drums for a specific DCU for a specified period of time. This provides a more consistent basis for the averaging period and allows the same operational flexibility for small refineries as large refineries. Based on the ICR responses, the median (typical) DCU has 60 venting events in a 30-day period. Providing an averaging period of 60 venting events provides a more consistent averaging basis for all facilities, regardless of the number of DCU at the facility and the number of drums and cycle times for different DCU. Additionally, it eliminates issues with respect to how to handle operating days versus non-operating days,
We have consistently maintained our policy to round to the last digit provided in the emission limit, a pressure of 2.4 psig would round to 2 psig and would be compliant with a requirement to depressure each coke drum to a closed blowdown system until the coke drum vessel pressure is 2 psig or less, but it would not be compliant with the revised new source provision to depressure until the coke drum vessel pressure is 2.0 psig or less. A coke drum pressure of 2.04, however, would be compliant with the revised new source requirement pressure limit of 2.0 psig.
A few commenters suggested that the EPA based the proposed combustion zone limits on an invalid data analysis, that the 1 minute PFTIR data should not be used to establish combustion efficiency correlations, and that the emission limits should be set so as to provide an equal chance of false positives and negatives. A few commenters suggested that the EPA should assign hydrogen a heating value of 1,212 BTU/scf to more accurately reflect its flammability in a NHV basis and that doing so is consistent with some recent flare consent decrees and would help reduce natural gas supplementation for facilities complying only with the NHVcz metric.
Several commenters suggested that neither scientific literature nor the available flare test data support the EPA's claim of an adverse hydrogen-olefin interaction on combustion efficiency and that the EPA should not finalize the more restrictive combustion zone operating limits for all flare types. These commenters suggested that the EPA did not provide any evidence the assumed hydrogen-olefin effect actually exists; that statistical analysis demonstrates the EPA developed their limit based on random differences in data; that the PFTIR data analysis method of using the individual minute-by-minute data instead of the test average data is flawed and leads to invalid conclusions; and that proper analysis of the data demonstrates the more stringent operating limits for hydrogen-olefin conditions cannot be supported.
Some commenters suggested that there is evidence to support more stringent flare combustion zone limits for a narrowly defined high concentration propylene-only condition as outlined in some of the recent flare
Several commenters suggested that the proposed 15-minute feed forward averaging time for flares (
Next, we evaluated the 15-minute run data using the normal net heating value for hydrogen of 274 Btu/scf, which is the value we used in the analysis for the proposed rule and also evaluated the data using the 1,212 Btu/scf, the value recommended by some commenters. The 1,212 Btu/scf value is based on a comparison between the lower flammability limit and net heating value of hydrogen compared to light organic compounds and has been used in several consent decrees to which the EPA is a party. Based on our analysis, we determined that using a 1,212 Btu/scf value for hydrogen greatly improves the correlation between combustion efficiency and the combustion zone net heating value over the entire array of data. Using the net heating value of 1,212 Btu/scf for hydrogen also greatly reduced the number of “type 2 failures” (instances when the combustion efficiency is high, but the gas does not meet the NHVcz limit). One of the primary motivations for the proposed approach to provide alternative limits based on lower flammability limits and combustibles concentrations was to reduce these type 2 failures. Therefore, we proposed all three of these parameters (
Next, we re-evaluated whether to finalize the proposed dual combustion zone operating limits for refinery flares that met certain hydrogen-olefins interactions or to finalize a single combustion zone net heating value limit. The newly re-compiled PFTIR run average flare dataset suggests that higher operating limits may be appropriate for some olefin-hydrogen mixtures. However, the dataset using 15-minute test average runs is much smaller than the set using 1-minute runs and thus creates a greater level of uncertainty. In addition, we cannot definitively conclude that a dual combustion zone limit for refinery flares meeting certain hydrogen-olefins interactions is appropriate given these uncertainties. Thus, in order to minimize these uncertainties and streamline the compliance requirements, we used all of the 15-minute test run average data together as a single dataset in an effort to determine an appropriate, singular combustion zone net heating value operational limit.
Finally, we conducted a Monte Carlo analysis to help assess the impacts of extending the averaging time on the test average flare dataset of 15-minute runs to 1-hour or 3-hour averaging time alternatives. While we consider it reasonable to provide a longer averaging time for logistical reasons, the Monte Carlo analysis demonstrated, consistent with concerns described in our proposal, that short periods of poor performance can dramatically limit the ability of a flare to achieve the desired control efficiency. Consequently, we find it necessary to finalize the proposed 15-minute averaging period to ensure that the 98-percent control efficiency for flares is achieved at all times. However, we understand that flare vent gas flow and composition are variable. While a short averaging time is needed to ensure adequate control given this variability, we also understand the complications that this variability places on flare process control in efforts to meet the NHVcz limit. Therefore, we are clarifying that the 270 Btu/scf NHVcz value is an operational limit that must be calculated according to the requirements in this rule. We also clarify that compliance with this operational limit must be evaluated using the equations and calculation methods provided in the rule. We proposed a feed forward calculation method to allow refinery owners or operators a means by which to adjust steam (or air) and, if necessary, supplemental natural gas flow, in order to meet the limit. In other words, “feed forward” refers to the fact that the rule requires the refinery owners or operators to use the net heating value of the vent gas (NHVvg) going into the flare in one 15-minute period to adjust the assist media (
Alternatively, if the owner or operator is able to directly measure the NHVvg on a more frequent basis, such as with a calorimeter (and optional hydrogen analyzer), the process control system is able to adjust more quickly, and the owner or operator can make adjustments to assist media or supplemental natural gas more quickly. In this manner, the owner or operator is not limited by
Based on the results of all of our analyses, the EPA is finalizing a single minimum NHVcz operating limit for flares subject to the Petroleum Refinery MACT standards of 270 BTU/scf during any 15-minute period. The agency believes, given the results from the various data analyses conducted, that this operating limit is appropriate, reasonable and will ensure that refinery flares meet 98-percent destruction efficiency at all times when operated in concert with the other suite of requirements refinery flares need to achieve (
To support their suggestions, commenters pointed out that flaring during emergencies is the optimum way of handling very large releases and that the flare test data clearly demonstrate that visible emissions and/or high flare tip velocity do not suggest poor destruction efficiency during such events. The commenters also argued that operators should not have conflicting safety and environmental considerations to deal with during these times. The commenters stated that refiners are still subject to a civil suit even if the EPA uses its enforcement discretion where such a release would violate the limit and in order to avoid such liability, many new flares would have to be built. Commenters estimated that 500 new large flare systems at a capital cost in excess of $10-20 billion would need to be built because of the amount of smokeless design capacity that would be needed and that this significant investment would take the industry at least a decade to install.
As an alternative to the proposed requirement that flares meet the visible emissions and velocity limits at all times, we considered a work practice standard for the limited times when the flow to the flare exceeds the smokeless capacity of the flare. Owners or operators of flares would establish the smokeless capacity of the flare based on design specification of the flare. Below this smokeless capacity, the velocity and visible emissions standards would apply as proposed. Above the smokeless capacity, flares would be required to perform root cause analysis and take corrective action to prevent the recurrence of a similarly caused event. Multiple events from the same flare in a given time period would be a deviation of the work practice standard.
Based on industry claims that there is a hydraulic load flaring event, on average, every 4.4 years, we assumed the best performers would have no more than one event every 6 years, or a probability of 16.7-percent of having an event in any given year. We found that, over a long period of time such as 20 years, half of these best performers would have 2 events in a 3 year period, which would still result in over half the “best performing” flares having a deviation of the work practice standard if it was limited to 2 events in 3 years. Conversely, only 6 percent would have 3 events in 3 years over this same time horizon. Based on this analysis, 3 events in 3 years would appear to be “achievable” for the average of the best performing flares.
Pursuant to CAA section 112(d)(2) and (3), we are finalizing a work practice standard for flares that is based on the best practices of the industry, and considers the rare hydraulic load events that inevitably occur at even the best performing facilities.
The best performing facilities have flare management plans that include measures to minimize flaring during events that may cause a significant release of material to a flare. Therefore, we are requiring owners or operators of affected flares to develop a flare management plan specifically to identify procedures that will be followed to limit discharges to the flare as a result of process upsets or malfunctions that cause the flare to exceed its smokeless capacity. We are specifically requiring refinery owners or operators to implement appropriate prevention measures applicable to these
Some commenters noted that the required control efficiency for some refinery emissions sources subject to subpart CC sources is 95-percent. One commenter also requested that the EPA provide overlap provisions so flares used to control sources from different MACT sources would not have duplicative requirements.
The commenters note that some subpart CC emissions sources have only a control efficiency requirement of 95-percent. While this may be true, where the owner or operator chooses to control these sources through the use of a flare, operation of that flare was subject to operational requirements in the General Provisions at 40 CFR 63.11 and the best performing flares were achieving 98-percent control at the time the General Provisions were promulgated. At the time the General Provisions were promulgated, we received no comments that the EPA should set different operational limits for flares that are controlling emissions from sources where the standard may vary by level of control efficiency and we see no basis to do so now. The purpose of the revisions to the flare operating requirements is to ensure that flares are operating consistent with the MACT floor requirements for any and all sources that may use flares as a control device (79 FR 36905, June 30, 2014). As the MACT floor control requirements of certain refinery sources that allow the use of a flare as a control device is 98-percent, we established operational limits to ensure flares used as control devices meet this MACT requirement.
To the extent that the commenters are requesting that the EPA establish an alternative monitoring approach for flares in dedicated service that have consistent composition and flow, we agree that these types of flares, which have limited flare vent gas streams, do not need to have the same type of on-going monitoring requirements as those with more variable waste streams. Thus, we are establishing an option that refinery owners or operators can use to demonstrate compliance with the operating requirements for flares that are in dedicated service to a specific emission source, such as a wastewater treatment operation. Refinery owners or operators will need to submit an application for the use of this alternative. The application must include a description of the system, characterization of the vent gases that could be routed to the flare based on a minimum of 7 grab samples (14 daily grab samples for continuously operated flares) and specification of the net heating value that will be used for all flaring events (based on the minimum net heating value of the grab samples). We are also allowing engineering estimates to characterize the amount of gas flared and the amount of assist gas introduced into the system. For example, the use of fan curves to estimate air assist rates is acceptable. Flare owners or operators would use the net heating value determined from the initial sampling phase and measured or estimated flare vent gas and assist gas
In general, we expect that the NHV
Another commenter stated that the EPA should require, as the Bay Area Air Quality Management District (BAAQMD) does, that any refinery that has a reportable PRD event must take certain steps to prevent such releases in the future (BAAQMD Rule 8-28-304). In particular, such a refinery must create a Process Hazard Analysis, meet the Prevention Measures Procedures specified in section 8-28-405, and conduct a failure analysis of the incident, to prevent recurrence of similar incidents (Id. Reg. section 8-28-304.1). If a second release occurs, then, within one year, the facility must vent its PRDs to a vapor recovery or disposal system that meets certain requirements (Id. Reg. section 8-28-304.2). The commenter asserted that the EPA's prohibition on releases to the atmosphere from PRD will ensure that refineries take the necessary steps to prevent such releases, or install control devices so that any releases from PRDs that must occur are vented through a control device to reduce the amount of toxic air pollution they emit. At a minimum, the commenter stated, the EPA must prohibit these uncontrolled emissions and require monitoring and reporting to assure compliance and ensure that the emission standards apply at all times, as required by the Act. The commenter argued that the EPA must also, however, consider requiring the additional developments that have been put into place in the BAAQMD and also require control devices to be used for all PRD, as some local air districts require. In addition, the commenter supported the EPA's monitoring and reporting requirements for PRD releases and the proposed electronic reporting requirements, which the EPA recognized are needed to assure compliance and assist with future rulemakings and as that provision requires, the EPA also must make all information reported publicly available online promptly and in an accessible and understandable format.
To estimate the impact of the proposed prohibition on venting PRDs to the atmosphere, we estimated that at least one new flare per facility would be required to handle releases from PRDs, based on the number of atmospheric PRDs reported at refineries; that 60-percent of the PRDs could be piped to existing controls at minimal costs and the other 40-percent would have to be piped to new flares; and that, on average, each new flare would service 40 PRDs. Based on these assumptions, 151 new flares would be needed or approximately one new flare per refinery. At a capital cost of $2 million for each new flare, which would not include long pipe runs, if needed, to PRD that are dispersed across the plant, we estimate that the capital cost of the
PRDs are unique in that they are designed for the purpose of releasing or “popping” as a safety measure to address pressure build-up in various systems—pipes, tanks, reactors—at a facility. These pressure build-ups are typically a sign of a malfunction of the underlying equipment. While it would be difficult to regulate most malfunction events because they are unpredictable and can vary widely, in the case of PRDs, they are equipment installed specifically to release during malfunctions and as such, we have information on PRDs in our 2011 Refinery ICR and through the SCAAMD and BAAQ rules to establish standards for them. After reviewing these comments, we thus examined whether it would be feasible to regulate these devices under CAA section 112(d)(2) and (3).
After reviewing the comments, we agree with the commenters who suggest that the BAAQMD rule, as well as a similar South Coast Air Quality Management District (SCAQMD) rule that address PRD releases (SCAQMD Rule 1173), provide work practice standards that reflect the level of control that applies to the best performers. Consequently, we developed a work practice standard for PRD based on a detailed MACT analysis considering the requirements in these rules. Our rationale for the selected MACT requirements is provided in section IV.C.4 of this preamble. The work practice standards that we are finalizing for PRDs require refiners to establish proactive measures for each affected PRD to prevent direct release of HAP to the atmosphere as a result of pressure release events. In the event of an atmospheric release, we are requiring refinery owners or operators to conduct root cause analysis to determine the cause of a PRD release event. If the root cause was due to operator error or negligence, then the release would be a deviation of the standard. For any other release (not including those caused by force majeure events), the owner or operator would have to implement corrective action. A second release due to the same root cause for the same equipment in a 3-year period would be a deviation of the work practice standard. Finally, a third release in a 3-year period would be a deviation of the work practice standard, regardless of the root cause.
With respect to defining “atmospheric pressure relief safety valve” as suggested by the commenter, we note that the June 30, 2014, proposed amendments in 40 CFR 63.648(j) used the term “relief valve” because this was a defined term in Refinery MACT 1. However, the proposed amendments included clauses such as “if the relief valve does not consist of or include a rupture disk.” Thus, we specifically intended to apply the pressure relief management requirements broadly to “pressure relief devices” and not just “valves.” To clarify this, we have revised the regulatory language to use the term “pressure relief device” rather than “relief valve” to clearly include rupture disks or similar types of equipment that may be used for pressure relief.
We revised the MACT floor determination for DCU sources. CAA section 112(d)(3)(A) requires the MACT floor for existing sources to exclude “. . . those sources that have, within 18 months before the emission standard is proposed or within 30 months before such standard is promulgated, whichever is later, first achieved a level of emission rate or emission reduction which complies, or would comply if the source is not subject to such standard, with the lowest achievable emission rate (as defined by section 171) applicable to the source category and prevailing at the time, in the category or subcategory for categories and subcategories with 30 or more sources.” Because we have determined that a 2 psig emissions limitation is equivalent with a LAER emission limit for DCU, we revised the MACT floor analysis in order to exclude sources that first met the 2 psig limit on or after December 30, 2012. For existing sources, based on the revised MACT analysis, we concluded that the MACT floor is still 2 psig. However, because the information on which we relied was submitted in response to the 2011 Petroleum Refinery ICR which requested “typical” venting pressures and because providing an allowance to average across venting periods does not reduce the emissions reductions achieved, we are providing a 60-event averaging period for existing sources in response to public comments received.
For new DCU sources, our revised analysis identified one DCU subject to permit emission limitations of 2.0 psig pressure limit prior to venting on a per event basis. Under CAA section 112(d)(3), the MACT standard for new sources cannot be less stringent than the emission control achieved in practice by the best-controlled similar source. Thus, we are finalizing a limit of 2.0 for new DCU sources. We note that as 2.0 psig limit is more stringent than a 2 psig limit because of the rounding convention of rounding to the number of significant digits for which the standard is expressed. For example, a 2.4 psig venting pressure is compliant with a 2 psig limit, while it is not compliant with a 2.0 psig limit.
We evaluated the costs of requiring existing sources to meet a 2.0 psig limit as a beyond-the-MACT-floor option. We determined the incremental cost of going from a 2 psig limit with an allowance to average over 60 events to a 2.0 psig limit on a per event basis was approximately $70,000 per ton of HAP reduced considering VOC credits. Based on this high incremental cost-effectiveness, we concluded that the MACT floor requirement for existing DCU sources was MACT. As discussed in detail in the proposal, we do not consider it technically feasible to meet a 1 psig pressure limit (effectively a 1.4 psig limit) on a not-to-be-exceeded basis. Thus, we rejected this beyond the floor control option for both existing and new DCU sources. See the memorandum titled “Reanalysis of MACT for Delayed Coking Unit Decoking Operations” in Docket ID No. EPA-HQ-OAR-2010-0682 for additional details regarding our re-analysis of MACT for DCU decoking operations.
In response to comments received on the prohibition of draining prior to achieving the proposed pressure limit (see Section 7.2.1 in the “National Emission Standards for Hazardous Air Pollutants from Petroleum Refineries—Background Information for Final Amendments: Summary of Public Comments and Responses” in Docket ID No. EPA-HQ-OAR-2010-0682), we are providing specific provisions to allow for draining under special conditions. The specific provision and our rationale for providing them are provided below.
First, we learned that certain DCU are designed to completely fill the drum with water and allow the water to overflow in the overhead line and drain to a receiving tank in order to more effectively cool the coke bed. Owners or operators of this DCU design were concerned that the water overflow may be considered a drain and also stated that overhead temperature rather than pressure would be a better indicator of effective bed cooling. In reviewing this
Second, we received comments that, for conventional DCU (those not designed to allow water overflow), there is a limit to the maximum water level in the drum, which limits to some extent how much cooling water can be added to the coke drum. In rare cases, the coke drum does not cool sufficiently using the typical cooling steps. In this case, the common industry practice is to partially drain the coke drum and refill it with additional cooling water. This “double-quench” process is needed for safety reasons to sufficiently cool the coke drum contents prior to the decoking operations. Therefore, commenters requested provisions to allow double-quenching of the coke drum. We recognize the safety issues associated with coke blow-out during coke cutting if there is a portion of the coke bed that is not sufficiently cooled and we agree that double-quenching is an effective means to cool the coke drum in those rare instances that the typical cooling cycle does not sufficiently cool the coke drum contents, so we considered granting the commenters' request. As noted previously, the primary concern with early draining of the coke drum is the emissions that are expected to occur as a result of draining superheated water. We recognize, however, that the water temperature near the bottom of the coke drum is typically much lower than at the top of the coke drum. If the temperature of the water drained from the bottom of the coke drum remains below 210 °F, this would minimize steam flashing and associated HAP emissions since the water drained would not be superheated. We conclude that the use of double quenching is appropriate for cases when the coke drum is not sufficiently cooled using the normal cooling procedures provided the temperature of the water drained remains below 210 °F, and it is consistent with the practices of the best performing sources. Consequently, we are finalizing provisions to allow the use of double-quenching for DCU provided the temperature of the water drained remains below 210 °F.
For the CRU, we are finalizing the proposed revisions to require CRU that employ active purging to meet the MACT emissions limitations in Tables 15 and 16 in subpart UUU at all times regardless of vessel pressure. We received limited comments regarding our proposal; these comments generally concerned the costs associated with the proposed emissions limitations. As discussed in our proposal, and based on data submitted in response to the ICR, emissions using active purging are much higher than those not using active purging. In the original rule, we based the MACT floor on the best performing facilities that used sequential pressurizations and depressurizations rather than active purging. Thus, in the proposal, we concluded that allowing owners or operators to actively purge while at low pressures was inconsistent with the MACT floor emissions limitations achieved by the best performing 12-percent of sources when the MACT floor was originally established. As we are simply requiring these facilities to meet the same emission levels determined to be MACT, we do not consider costs of potential additional controls to be a viable rationale to allow these units to emit several times more HAP than the units upon which the MACT requirements were based and the emissions levels achieved in practice by the vast majority of other CRU sources.
For flares, we are finalizing proposed revisions to include detailed flare monitoring and operating requirements. We are including the flaring provisions for refineries in the Refinery MACT rules and removing the cross-references to the flaring requirements in the General Provisions. The final regulatory requirements differ from the proposed requirements in several respects. First, we are not finalizing the ban on halogenated vent streams because we did not include sufficient justification or include cost estimates for this proposed provision and we did not include any monitoring requirements to ensure compliance with this ban on halogenated vent streams.
We are finalizing the proposed no visible emissions limit and the flare tip velocity limit but they will apply only when the flare vent gas flow rate is below the smokeless capacity of the flare. We received a number of comments stating that the no visible emissions limit and the flare tip velocity limit cannot be met during large malfunctions and emergency shutdown events. In response to comments, we are finalizing work practice standards for emergency flaring events using the proposed no visible emission limit and flare tip velocity limit as thresholds in the final rule to trigger root cause analysis when the flare vent gas flow rate is above the smokeless capacity of the flare. The final work practice standard includes requirements to develop a flare management plan, to implement prevention measures, and to perform root cause analysis and implement corrective action following each flaring event that exceeds the smokeless capacity of the flare. There is also a limit on the number of these flaring events that a given flare may have in the 3-year period. We are establishing these provisions because we now recognize that flares have two different design capacities: A smokeless design capacity and a hydraulic load capacity. We determined that the proposed visible emissions limit and the flare tip velocity limit for very large flow events are not the MACT floor for such events. The final work practice standards for flaring events are based on the best performing facilities and will result in emission reductions in a technically feasible manner without any negative secondary impacts.
We consider it appropriate to establish a work practice standard for flares as provided in CAA section 112(h). While it is possible to monitor gaseous streams going into the flare (as we have required for the flare operating requirements) it is not possible to design and construct a conveyance to capture the emissions from a flare. While knowledge of the composition and flow of gases entering the flare provides a reasonable basis for establishing operating requirements for normal operations, we have no data on flare performance under conditions in the hydraulic load range. While smoke in the flare exhaust is an indication of incomplete combustion, it is uncertain
We also received comments that the daily visible emissions observations were burdensome and unnecessary and some commenters suggested that facilities be allowed to use video surveillance cameras. We concluded that video surveillance cameras would be at least as effective as the proposed daily 5-minute visible emissions observations using Method 22. We are finalizing the proposed visible emissions monitoring requirements Method 22 and the alternative of using video surveillance cameras.
We are simplifying the combustion zone gas property operating limits in response to public comments received. Specifically, we are finalizing requirements that all flares meet a minimum operating limit of 270 BTU/scf NHV
For air-assisted flares, we are finalizing the additional “dilution parameter” operating limit only for the net heating value dilution parameter, NHV
For flares in dedicated service, we are establishing an alternative to continuous or on-going grab sample requirements for determining waste gas net heating content to reduce the burden of sampling for flare waste gases that have consistent compositions. Flares in dedicated service can use initial sampling period and process knowledge to determine a fixed net heating value of the flare vent gas to be used in the calculations of NHV
We are revising the definition of MPV to remove the exemption for in situ sampling systems for the reasons provided in the proposed rule.
We received comments recommending that a work practice standard be adopted for PRD rather than the proposed prohibition of atmospheric PRD releases. Commenters stated that the prohibition was infeasible due to the proposed immediate timing of the requirement and impractical due to cost considerations. After reviewing these comments as well as the BAAQMD rule (Regulation 8, Rule 8-28-304) and the SCAQMD rule (Rule 1173), we have determined that the work practice standards in these rules reflect the level of control that applies to the best performers. Therefore, we proceeded to evaluate appropriate MACT requirements based on the provisions in these rules.
The BAAQMD rule requires sources to implement a minimum of three prevention measures to limit the possibility of a release. The BAAQMD uses a “release event” threshold of 10 lbs/day of organic or inorganic pollutants; the SCAQMD rule effectively uses a release event threshold of 500 lbs VOC/day. When a release event occurs, both rules require that the refiner perform a root cause analysis and take corrective action (including additional prevention measures). In addition, both rules require piping the PRD to a flare if there are more than two release events (releases above a certain release size threshold) in a 5-year period. Both rules include a number of exemptions for certain types of PRD that are not expected to release significant amounts of pollutants to the air or that are not feasible to control because of pressure considerations. These include PRD associated with storage tanks, vacuum systems and equipment in heavy liquid service as well as liquid thermal relief valves that are vented to process drains.
There are five refineries subject to the BAAQMD rule and seven refineries subject to the SCAQMD rule, accounting for 8-percent of refineries nationwide and representing the industry's best performers. We consider the BAAQMD rule to be the more stringent of the two because this rule requires sources to implement a minimum of three prevention measures to limit the possibility of a release (the SCAQMD rule has no similar requirement) and uses a lower mass threshold for what is considered a “release event” (10 lbs/day of organic or inorganic pollutants versus the 500 lbs VOC release threshold in the SCAQMD rule). Therefore, the BAAQMD rule is considered to be the MACT floor requirement for PRDs associated with new affected sources and the SCAQMD rule is considered to be the MACT floor for PRDs associated with existing affected sources.
In general, an open PRD is essentially the same as a miscellaneous process vent that is vented directly to the atmosphere. Consistent with our treatment of miscellaneous process vents and consistent with the two California rules, we believe that it is appropriate to exclude certain types of PRD that have very low potential to emit based on their type of service, size and/or pressure. For example, PRD that have a potential to emit less than 72 pounds per day of VOC, considering the size of the valve opening, design release pressure, and equipment contents, would be considered in a similar manner as Group 2 miscellaneous
Any release from a PRD in heavy liquid service would have a visual indication of a leak and any repairs to the valve would have to be further inspected and, if necessary, repaired under the existing equipment leak provisions. Therefore, consistent with the BAAQMD rule, we are exempting PRD in heavy liquid service from the work practice standards we are establishing in this final rule.
Both the BAAQMD and SCAQMD rules exempt thermal expansion valves that are “vented to process drains or back to the pipeline.” We are unclear what is meant by “vented to process drains”; however, if a liquid is released from a PRD via hard-piping to a drain system that meets the control requirements specified in Refinery MACT 1, we consider that these PRD are controlled and they would not be subject to the work practice standard established in this final rule. Similarly, all PRD in light liquid service that are hard-piped to a controlled drain system (or back to the process or pipeline) are otherwise subject to a MACT requirement and would not be subject to the work practice standard.
In considering thermal relief valves not vented to process drains or back to the pipeline, we expect that releases from these thermal relief valves will be small and generally under the release event thresholds specified in the California rules. Therefore, the work practice standards do not apply to PRD that are designed solely to release due to liquid thermal expansion.
The primary goal of the PRD work practice standard is to reduce the size and frequency of releases. The SCAQMD rule is targeted towards fairly large releases (compared to the direct PRD releases reported in response to the Refinery ICR), so it will reduce the frequency of large releases, but it does little to reduce the frequency of smaller releases. To more effectively reduce the size and frequency of all releases, we consider it important to require the implementation of prevention measures (as required in the BAAQMD rule) and require root cause analysis and corrective action for PRD releases from all PRD subject to the work practice standard. While we recognize that if a PRD opens for a short period of time, the release might be below the release thresholds in the SCAQMD rules, we believe the release may be indicative of an important issue or design flaw. Because the potential for large emissions exist from the PRD subject to the work practice standard, we think it is reasonable to require a root cause analysis be conducted and appropriate corrective action implemented to potentially identify this issue and prevent a second release which, if the issue remains uncorrected, could be significant.
Requiring that prevention measures be implemented on all PRD subject to the work practice standard and not establishing a release threshold for release events is a variation from the SCAQMD rule. However, we also considered the allowable release frequency. We believe that our adoption of this approach is balanced by our not adopting the SCAQMD provisions requiring that PRD be vented to a flare or other control system or that refiners pay a fee if there are multiple releases of a certain size within a specified timeframe.
Because we are not including a size threshold for release events as in the SCAQMD rule, it is natural to assume release events would occur more frequently than release events subject to the SCAQMD rules. Also, based on our Monte Carlo analysis of random rare events, we note that it is quite likely to have two or three events in a 5-year period when a long time horizon (
The SCAQMD work practice standards do not apply to releases that are demonstrated to “result from natural disasters, acts of war or terrorism, or external power curtailment beyond the refinery's control, excluding power curtailment due to an interruptible service agreement.” These types of events, which we are referring to as “
Consistent with the requirements in the SCAQMD rule, we are requiring refinery owners or operators to conduct a root cause analysis for a PRD release event. If the root cause was due to operator error or negligence, then the release would be a deviation of the standard. For any other release (not including those caused by
We also considered requiring all PRD to be vented through a closed vent system to a control device as an alternative beyond-the-MACT floor requirement. While this requirement would provide additional emission reductions beyond those we are establishing as the MACT floor, these reduction come at significant costs. Capital costs for requiring control of all atmospheric PRD is estimated to be approximately $300 million compared to $11 million for the requirements described above. The total annualized cost for requiring control of all atmospheric PRD is estimated to be approximately $41 million/year compared to $3.3 million/year for the requirements described above. We estimate that the incremental cost-effectiveness of requiring control of all atmospheric PRD compared to the requirements described above exceeds $1 million per ton of HAP reduced. Consequently, we conclude that this is not a cost-effective option for existing sources.
The final requirements that we have developed for PRD achieve equal or greater emission reductions than those achieved by the SCAQMD rule (MACT floor). To the extent those requirements are more stringent that the SCAQMD, they are cost-effective. We could not identify an alternative requirement that provided further emission reductions in a cost-effective manner. Thus, we conclude that the work practice standards described above represent MACT for existing sources.
The BAAQMD rule, which represents the requirements applicable to the best performing sources, is the basis for new source MACT for PRD. Based on the specific provisions for PRD in the BAAQMD rule, we conclude that the MACT floor requirement is to have all PRD in HAP service associated with a new affected source vented through a closed vent system to a control device. As with existing sources, the PRD WPS would also contain the same exclusions (
We consider it appropriate to establish a work practice standard for PRD as provided in CAA section 112(h). While it may be possible to design and construct a conveyance for PRD releases, we consider that the application of a measurement methodology for PRDs is not practicable due to technological and economic limitations. First, it is not practicable to use a measurement methodology for PRD releases. The venting time can be very short and may vary widely in composition and flow rate. The often-short duration of an event makes it infeasible to collect a grab sample of the gases when a release occurs, and a single grab sample would not account for potential variation in vent gas composition. It would be economically prohibitive to construct an appropriate conveyance and install and operate continuous monitoring systems for each individual PRD in order to attempt to quantitatively measure a release event that may occur only a few times in a 3-year period. Additionally, we have not identified an available, technically feasible continuous emission monitoring systems that can determine a mass VOC or HAP release quantity accurately given the flow, composition and composition variability of potential PRD releases from refineries. Consequently, we conclude that it is appropriate to establish a work practice standard for PRD releases as provided in CAA section 112(h).
We proposed to eliminate the SSM exemption in 40 CFR part 63, subparts CC and UUU. Consistent with
For Refinery MACT 1, we proposed that the use of a bypass at any time to divert a Group 1 miscellaneous process vent to the atmosphere is a deviation of the emission standard, and specified that refiners install, maintain and operate a continuous parameter monitoring system (CPMS) for flow that is capable of recording the volume of gas that bypasses the APCD.
We also proposed to revise the definition of MPV to remove the exclusion for “Episodic or non-routine releases such as those associated with startup, shutdown, malfunction, maintenance, depressuring and catalyst transfer operations.” We also proposed that the control requirements for Group 1 MPV apply at all times, including startup and shutdowns.
For Refinery MACT 2, we proposed alternate standards for three emission sources for periods of startup or shutdown. We proposed PM standards for startup of FCCU controlled with an ESP under Refinery MACT 2 because of safety concerns associated with operating an ESP during an FCCU startup. For FCCU controlled by an ESP, we proposed a 30-percent opacity limit (on a 6-minute rolling average basis) during the period that torch oil is used during FCCU startup. For startup of FCCU without a post-combustion device under Refinery MACT 2, we proposed a CO standard based on an excess oxygen concentration of 1 volume percent (dry basis) based on a 1-hour average. For periods of SRU shutdown, we proposed to allow diverting the SRU purge gases to a flare meeting the design and operating requirements in 40 CFR 63.670 (or, for a limited transitional time period, 40 CFR 63.11) or to a thermal oxidizer operated at a minimum temperature of 1,200 °F and a minimum outlet oxygen concentration of 2 volume percent (dry basis). For other emission sources in Refinery MACT 2, we proposed that the requirements that apply during normal operations should apply during startup and shutdown.
We proposed that when process equipment is opened to the atmosphere (
We are expanding the proposed 1-percent minimum oxygen operating limit alternative for organic HAP to apply for all FCCU startup and shutdown events (rather than only partial burn FCCU with CO boilers during startup). We are replacing the proposed opacity limit alternative to the metal HAP standard with a minimum cyclone face velocity limit and we are extending that alternative limit to all FCCU (regardless of control device) for both startup and shutdown in this final rule.
We are extending the proposed alternative for SRU to monitor incinerator temperature and excess oxygen limits during SRU shutdowns to also apply during periods of startup.
Many commenters stated that every time a vessel is opened for inspection or maintenance each vent point will have to be evaluated as a potential MPV or storage tank vent. If a particular vent point (
Commenters recommended a general set of work practice requirements for maintenance, startup and shutdown of vents, based on state requirements, that do not impose the permitting, notice and evaluation requirements associated with identifying these vents individually. Commenters explained that states have dealt with these episodic vents by establishing them as a special class of process vent with limited recordkeeping requirements and subject to a work practice standard, rather than the normal MPV requirements. A key element of these work practices is clear identification of the criteria for releasing these vents to the atmosphere and for routing these vents to control after hydrocarbon is reintroduced, which the commenters asserted the current rule does not provide. Commenters proposed that a work practice standard could include removing process liquids to the extent practical and depressuring smaller volume equipment until a pressure of <5 psig is achieved and/or purging and depressuring to a control device until the vent has a hydrocarbon concentration of less than 10-percent of the LEL. The commenters suggested that these standards should provide clear easily monitored criteria for when this equipment can be vented to the atmosphere, and should not impose the permitting, notice and evaluation requirements associated with identifying these vents as individual MPVs. One commenter provided draft regulatory language for a work practice requirement.
In considering these comments and whether we should establish a separate limit that would apply to these equipment openings, we reviewed state permit requirements and the practices employed by the best performing sources. We found that some state or local agencies required depressuring to 5 psig prior to atmospheric releases while others required the gases to have organic concentrations at or below 10-percent of LEL prior to atmospheric venting. In the final rule, we are establishing a requirement that prior to opening process equipment to the atmosphere, the equipment must first be drained and purged to a closed system so that the hydrocarbon content is less than or equal to 10-percent of the LEL. For those situations where 10-percent LEL cannot be demonstrated, the equipment may be opened and vented to the atmosphere if the pressure is less than or equal to 5 psig, provided there is no active purging of the equipment to the atmosphere until the LEL criterion is met. For equipment where it is not technically possible to depressurize to a
Several commenters stated that the EPA's limits on FCCU opacity during SSM are unreasonable and ignore the technical requirements for transitional operations of those units. The commenters indicated that they have ESPs located downstream of the CO boiler and claimed that for safety reasons the CO boiler cannot operate during startup, shutdown or hot standby. Further, a commenter indicated that the ESP cannot operate if the CO boiler is not operating and thus both the CO boiler and the ESP must be bypassed during startup, shutdown, and hot standby operations.
Another commenter stated that the EPA offers no data to support the achievability of this requirement in practice and discusses information for 26 startup/shutdown events that found that none complied with a 30-percent opacity requirement. Several commenters also noted that experience has shown that the 30-percent opacity limit is unachievable during these periods for FCCUs controlled with tertiary cyclones, when regenerator gas flow is below cyclone minimum design flow.
Several commenters suggested that the EPA establish a standard based on the operation of FCCU catalyst regenerators' internal cyclones that function to retain the catalyst in the regenerators and thereby minimize catalyst and metal HAP emissions from the regenerators. Additional control to meet the Refinery MACT 2 emission limit of not more than 1.0 lb PM/1,000 lbs coke burn-off is provided by a bag house, wet gas scrubber (WGS), ESP or tertiary (external) cyclone. The efficiency of a cyclone is a function of the inlet gas velocity. Assuring adequate velocity to the internal cyclones ensures that the catalyst sent to these additional controls is minimized and ensures that they are operating as effectively as possible. Similarly, even if the FCCU cannot meet the normal opacity limits during startup, shutdown or hot standby (
On the other hand, some commenters seemed to support the proposed opacity limits, but suggested minor revisions. One commenter noted that the SCAQMD has granted Valero's request for variances from visible emission standards during startup of the FCCU of up to 65-percent opacity for up to five minutes, in aggregate, during any 1-hour period, and 30-percent as an hourly average for the remaining period, during startup events. The application of this variance reflects the unavailability and/or ineffectiveness of the ESP during the startup condition. Another commenter recommended that either the opacity standard should be raised or the time period for averaging should be extended so FCCUs can be operated safely during SSM events and still remain in compliance.
Commenters stated that reliable boiler operation is critical to the overall refinery steam system and refineries must avoid jeopardizing boiler operation to prevent major upsets of process operations. A major upset or site-wide shutdown could result in flaring and emissions of HAP far in excess of that emitted while bypassing the CO boiler.
Commenters stated that combustion of torch oil in the FCCU regenerator during startup is one of the primary reasons the CO limit cannot be met during these operations. Torch oil is also used during shutdown to control the cooling rate (and potential equipment damage) and during hot standby and, thus, the normal CO standard cannot be met at these times either. Hot standby is used to hold an FCCU regenerator at operating temperature for outages where a regenerator shutdown is not needed and to avoid full FCCU shutdowns. Full cold shutdown also increases personnel exposures associated with removing catalyst and securing equipment. Additionally, this can produce additional emissions over maintaining the unit in hot standby. Commenters claimed that because of the variability of CO during torch oil operations, it is not possible for the EPA to establish a CAA section 112(d) standard for startup and shutdown activities at FCCU because refineries cannot measure a constant level of emissions reductions.
The commenters recommended expansion of the proposed standard of greater than 1-percent hourly average excess regenerator oxygen to all FCCU, including units with fired boilers. These commenters suggested that maintaining an adequate level of excess oxygen for the combustion of fuel in the regenerator is the best way to minimize CO and organic HAP emissions from FCCU during these periods.
We did not receive comments regarding the proposed amendments to Table 6 of subpart CC of 40 CFR part 63; therefore, for the reasons provided in the preamble to the proposed rule, we finalizing these amendments as proposed.
We determined that it was overly burdensome and in most cases technically infeasible to consider every potential equipment or vessel opening and classify these “openings” (newly classified as MPV in the proposal) as either Group 1 or Group 2 MPV. We also determined that it is not always technically feasible, depending on the opening, to demonstrate compliance with the MPV emissions limitations. After considering the public comments, we determined it was appropriate to establish separate startup and shutdown provisions for MPV associated with process equipment openings. We reviewed state and local requirements and based the final rule requirements on the emissions limitations required to be followed by the best performing sources. Therefore, we are finalizing requirements for refinery owners or operators to open process equipment during these startup and shutdown events without directly permitting these “vents” as Group 1 or Group 2 MPV provided that the equipment is drained and purged to a closed system until the hydrocarbon content is less than or equal to 10-percent of the LEL. As described in further detail previously in this section, we have provided provisions for special cases where the 10-percent LEL limit cannot be demonstrated and provisions for less significant equipment openings, consistent with the practices used by the best performing facilities.
We did not receive significant comments regarding the proposed amendments to Table 44 to subpart UUU of 40 CFR part 63; therefore, we finalizing these amendments as proposed.
In response to comments, we determined that the limited provisions that were provided for startup only or for shutdown only were too limited and we have expanded the proposed provisions to both startup and shutdown regardless of control device used. For the FCCU organic HAP emissions limit, we are finalizing an alternative limit for periods of startup of no less than 1-percent oxygen in the exhaust gas as proposed, but we are extending that alternative limit to shutdown and to all FCCU in this final rule.
For the FCCU metal HAP emissions limit, we proposed a specific startup limit for FCCU controlled be an ESP of 30-percent opacity. We received comments along with limited data suggesting that this limit was not achievable. Commenters suggested that the best performing units maintain a minimum face velocity of at least 20 feet/second to minimize catalyst PM losses during startup and shutdowns. Operators of wet scrubbers also noted that they cannot maintain pressure drops and that one cannot meet the PM emissions limit normalized by coke burn-off rate when the coke burn-off rate approaches zero. Consequently, commenters stated that the alternative limits should be provided for startup and shutdown regardless of control device. Upon consideration of the comments, we determined that it was necessary to revise the proposed
For SRU, we are finalizing an alternative standard during periods of startup and shutdown to use a flare that meets the operating limits included in the final rule or a thermal oxidizer or incinerator operated at a minimum hourly average temperature of 1,200 °F and a minimum hourly average outlet oxygen concentration of 2 volume percent (dry basis). We proposed these alternatives for periods of shutdown only, but based on comments received regarding startup issues, we determined that high sulfur loadings can occur during periods of startup and that the alternative limit proposed was appropriate for both startup and shutdown.
We proposed a number of amendments to Refinery MACT 1 and 2 to address technical issues such as rule language clarifications and reference corrections. First, we proposed to amend Refinery MACT 1 to clarify what is meant by “seal” for open-ended valves and lines that are “sealed” by the cap, blind flange, plug, or second valve by stating that sealed means when there are no detectable emissions from the open-ended valve or line at or above an instrument reading of 500 ppm. Second, we also proposed electronic reporting requirements where owners or operators of petroleum refineries must submit electronic copies of required performance test and performance evaluation reports for compliance with Refinery MACT 1 and 2 by direct computer-to-computer electronic transfer using EPA-provided software. Third, we proposed to update the General Provisions Tables 6 (for Refinery MACT 1) and 44 (for Refinery MACT 2) to correct cross references and to incorporate additional sections of the General Provisions that are necessary to implement these rules.
We are not finalizing the definition of “seal” for open-ended lines as proposed. We are finalizing changes to update the General Provisions cross-reference tables as proposed, with one minor change to provide an option for the administrator to issue guidance on performance test reporting timeframes in order to address issues relating to submittal of data to the ERT.
One commenter stated that none of the MACT standards in place before this proposal have stated or suggested that a “sealed” OEL is one with detectable emissions below 500 ppm. This commenter added this unique interpretation of the requirement to “seal” an OEL with a cap or plug is incompatible with the historical interpretation of this requirement by affected facilities and by the EPA, and the EPA has not issued any sort of definitive guidance or interpretation setting out this position. The commenter detailed numerous references to considerations the EPA has made relative to OEL requirements in LDAR programs. In addition to the examples cited, the commenter noted that in 2006, the EPA proposed to add a “no detectible emissions” limit and monitoring requirement for OELs to NSPS VV (71 FR 65317, November 7, 2006). Two commenters noted that the proposed monitoring was not finalized in either NSPS VV or VVa (72 FR 64860, November 16, 2007) because it was not considered BDT due to the low emission reductions and the cost effectiveness of the requirement. Another commenter agreed that there is no explanation provided for why this information could now support the need for a new OEL seal standard that requires monitoring to ensure compliance when it was deemed to be unjustified previously.
In addition, the commenter collected OEL monitoring data and submitted it to the EPA (see Docket Item No. EPA-HQ-OAR-2010-0869-0058). Based on these data, the commenter asserted that the existence of leaks from OELs that are not properly sealed is extremely low.
The commenter noted that the EPA is claiming this change is only a clarification of current requirements, allowing the EPA to bypass the need to cite a CAA authorization for this change to the existing CAA section 112(d)(2) standard or meet the process requirements associated with such a change, including providing emission reduction, cost and burden estimates in the record and the associated PRA Information Collection Request (ICR).
Several commenters claimed that this clarification would result in retroactive impact and also addressed the implication of the proposed change on other fugitive emissions standards. One commenter stated that the EPA cannot retroactively reinterpret the OEL requirements or define the word “seal” and added that the EPA should account for the thousands of additional monitoring events per year per refinery that this new requirement would add to LDAR programs and provide proper cost justification under CAA sections 112(d)(6) or 112(f)(2).
Several commenters also stated that the proposed definition will effectively change all equipment leak rules in parts 40 CFR parts 60, 61 and 63 and the change should not be finalized. One commenter added that by claiming this change is only a clarification of current requirements, the EPA would set a precedent applicable to all OELs in all industries subject to any similar OEL equipment leak requirement.
Other commenters stated that the ERT requirement does not supersede or replace any state reporting requirements and thus the regulated industry will be subject to dual reporting requirements. These commenters disagreed with the preamble claim that eliminating the recordkeeping requirements for performance test reports is a burden savings, and stated that it may duplicate burdens already borne by the regulated community.
The commenters expressed further concern that duplicative reporting requirements will strain the regulated industry to comply with deadlines established by rule for report submittals. One commenter stated that there is no mechanism for obtaining extensions for special circumstances. Under proposed 40 CFR 63.655(h)(9)(i), all reports are due in 60 days. The commenter claimed that by not referencing reporting requirements to the General Provisions in 40 CFR 63.10(d)(2), there is no allowance for obtaining additional time due to unforeseen circumstances or due to the difficulties involved with completing particularly complex reports.
One commenter stated that the primary performance test method (Method 18) required for determining compliance is not currently included in the list of methods supported by the ERT. The commenter stated that the regulated community's experience with Method 18 is that it is a very broad methodology and can be exceptionally complex to execute and to report. The commenter stated that the EPA is aware that Method 18 reporting is complex, that it may be difficult to incorporate into the ERT, and that no time schedule has been defined for development or implementation for this method.
The commenter also stated that without formal notice of changes to the ERT, the regulated community is at risk of non-compliance. The only way for the regulated community to know that changes have occurred in the ERT is to monitor the Web site directly because the EPA does not formally announce changes to the ERT in the
Furthermore, based on the analysis performed for the Electronic Reporting and Recordkeeping Requirements for the New Source Performance Standards Rulemaking (ERRRNSPS) (80 FR 15100), electronic reporting results in an overall cost savings to industry when annualized over a 20-year period. The cost savings is achieved through means such as standardization of data, embedded quality assurance checks, automatic calculation routines and reduced data entry through the ability to reuse data in files instead of starting from scratch with each test. As outlined in the ERRRNSPS, there are many benefits to electronic reporting. These benefits span all users of the data—the EPA, state and local regulators, the regulated entities and the public. We note that in the preamble to this proposed rule we provided a number of reasons why the use of the ERT will provide benefit going forward and that most of the benefits we outlined were longer-term benefits (
We think that it is a circular argument to say that the agency should eliminate the use of the ERT until it demonstrates that it is using the electronic data. It would be impossible for the agency to use data that it does not have. We can only use electronic data once we have electronic data. We do note that we are nearing completion of programming the WebFIRE database with our new emissions factor development procedures and anticipate running the routines on existing data sets in the near future.
We continue to improve and upgrade the ERT on an ongoing basis. The current version of the ERT supports 41 methods, including EPA Methods 1-4, 5, 5B, 5F, 25A 26, and 26A. We note that the ERT does not currently support EPA Method 18, and for performance tests using Method 18, the source will still have to produce a paper report. However, we are aware of the need to add Method 18 to the ERT, and we are currently looking at developing this capability. As noted in the ERRRNSPS, when new methods are added to the
We did revise the MACT 1 and 2 tables referencing reporting requirements to the general provisions (Table 6 for Refinery MACT 1 and Table 44 for Refinery MACT 2) to provide flexibility in the 60-day reporting timeline to accommodate unforeseen circumstances or difficulties involved with completing particularly complex reports.
We are not finalizing the definition of seal, as proposed. The fenceline monitoring work practice standard will detect any significant leaks from a cap, blind flange, plug or second valve that does not properly seal an OEL, as well as significant leaks from numerous other types of fugitive emission sources.
We are finalizing requirements for electronic reporting, as proposed, with a minor clarification. Specifically, we are revising Tables 6 in subpart CC and 44 in subpart UUU, which cross-reference the applicable provisions in the General Provisions to provide flexibility in the ERT 60-day reporting timeline. Refiners can seek approval from the EPA or a delegated state additional time for submittal of data due to unforeseen circumstances or due to the difficulties involved with completing particularly complex reports.
We proposed a number of amendments to Refinery NSPS subparts J and Ja to address reconsideration issues and minor technical clarifications. First, we proposed revisions to 40 CFR 60.100a(b) to include a provision that sources subject to Refinery NSPS subpart J could elect to comply instead with the provisions of Refinery NSPS subpart Ja.
Second, we proposed a series of amendments to the requirements for SRP in 40 CFR 60.102a, to clarify the applicable emission limits for different types of SRP based on whether oxygen enrichment is used. The amendments proposed also clarified that emissions averaging across a group of emission points within a given SRP is allowed for each of the different types of SRP, and that emissions averaging is specific to the SO
Third, we proposed amendments to 40 CFR 60.102a(g)(1) to clarify that CO boilers, while part of the FCCU affected facility, can also be FGCD.
Fourth, we proposed several revisions to 40 CFR 60.104a to clarify the performance testing requirements. We proposed revision to 40 CFR 60.104a(a) to clarify that an initial compliance demonstration is needed for the H
Fifth, we proposed several amendments to clarify the requirements for control device operating parameters in 40 CFR 60.105a. Specifically, we proposed amendments to 40 CFR 60.105a(b)(1)(ii)(A) to require corrective action be completed to repair faulty (leaking or plugged) air or water lines within 12 hours of identification of an abnormal pressure reading during the daily checks. We also proposed revisions to 40 CFR 60.105a(i) to specify that periods when abnormal pressure readings for a jet ejector-type wet scrubber (or other type of wet scrubber equipped with atomizing spray nozzles) are not corrected within 12 hours of identification and periods when a bag leak detection system alarm (for a fabric filter) is not alleviated within the time period specified in the rule are considered to be periods of excess emissions.
We also proposed amendments to 40 CFR 60.105(b)(1)(iv) and 60.107a(b)(1)(iv) to provide flexibility in span range to accommodate different manufacturers of the length-of-stain tubes. We also proposed to delete the last sentence in 40 CFR 60.105(b)(3)(iii).
Finally, we proposed clarification to the performance test requirements for the H
We are making very few changes to the amendments proposed for Refinery NSPS subparts J and Ja. In response to comments, we are revising the NSPS requirements to replace the “measurement sensitivity” requirements with accuracy requirements consistent with those used in Refinery MACT 1 and 2. Specifically, we are revising 40 CFR 60.106a(a)(6)(i)(B) and (7)(i)(B) to require use of a flow sensor meeting an accuracy requirement of ±5-percent over the normal range of flow measured or 10-cubic-feet-per-minute, whichever is greater. We are also revising the flare accuracy requirements in 40 CFR 60.107a(f)(1)(ii) to require use of a flow sensor meeting an accuracy requirement of ±20-percent of the flow rate at velocities ranging from 0.1 to 1 feet per second and an accuracy of ±5-percent of the flow rate for velocities greater than 1-feet-per-second.
Finally, we are revising 40 CFR 60.101a(b) to correct an inadvertent error where the phrase “and delayed coking units” was not included in the proposed sentence revision.
We are finalizing amendments for Refinery NSPS subparts J and Ja as proposed with minor revisions. In response to comments, we are revising the “measurement sensitivity” requirements to be an “accuracy” requirement. This change will make the requirements more clear and consistent between the flow meter requirements in the NSPS and the MACT standards since the same flow meter will be subject to each of these requirements. We are also providing a dual accuracy requirement for flare flow meters. This accuracy requirement is necessary because flares, which can have large diameters to accommodate high flows, are commonly operated at low flow rates. Together, this makes it technically infeasible for many flares to meet the lower flow 10 cfm accuracy requirement. Therefore, we are providing specific accuracy requirements for flares of ±20-percent over the velocity range of 0.1-1 ft/s and ±5-percent for velocities exceeding 1 ft/s, consistent with recent consent decrees and equipment vendor specifications.
Finally, we are revising the introductory phrase in the first sentence in 40 CFR 60.101a(b) to read “Except for flares and delayed coking units . . .” to correct an inadvertent error. We intended to revise this sentence only to include the proposed provision to allow sources subject to Refinery NSPS subpart J to comply with Refinery NSPS subpart Ja. The redline text posted on our Web site showed no revisions to this introductory phrase, but the amendatory text did not include the words “and delayed coking units” in this phrase. This was an inadvertent error, which we are correcting in the final rule.
The sources affected by significant amendments to the petroleum refinery standards include flares, storage vessels, pressure relief devices, fugitive emissions and DCU. The amendments for other sources subject to one or more of the petroleum refinery standards are expected to have minimal air quality and cost impacts.
The total capital investment cost of the final amendments and standards is estimated at $283 million, $112 million from the final amendments for storage vessels, DCU and fenceline monitoring and $171 million from standards to ensure compliance. We estimate annualized costs of the final amendments for storage vessels, DCU and fenceline monitoring to be approximately $13.0 million, which includes an estimated $11.0 million for recovery of lost product and the annualized cost of capital. We also estimated annualized costs of the final standards to ensure compliance to be approximately $50.2 million. The final amendments for storage vessels, DCU and fenceline monitoring would achieve a nationwide HAP emission reduction of 1,323 tpy, with a concurrent reduction in VOC emissions of 16,660 tpy and a reduction in methane emissions of 8,700 metric tonnes per year. Table 2 of this preamble summarizes the cost and emission reduction impacts of the final amendments, and Table 3 of this preamble summarizes the costs of the final standards to ensure compliance.
The impacts shown in Table 2 do not include costs, product recovery credits, or emissions reductions associated with any root cause analysis or corrective action taken in response to the final amendments for fenceline monitoring. The impacts shown in Table 3 do not include (i) the costs or emissions reductions associated with any root cause analysis and corrective action taken in response to the final source performance testing at the FCCUs, or (ii) emissions reductions associated with corrective action taken in response to pressure relief device or (iii) emissions reductions associated with the flare operating and monitoring provisions. The operational and monitoring requirements for flares at refineries have the potential to reduce excess emissions from flares by up to approximately 3,900 tpy of HAP and 33,000 tpy of VOC. The operational and monitoring requirements for flares also have the potential to reduce methane emissions by 25,800 metric tonnes per year while increasing emissions of carbon dioxide (CO2) and nitrous oxide by 267,000 metric tonnes per year and 2 metric tonnes per year, respectively, yielding a net reduction in GHG emissions of 377,000 metric tonnes per year of CO2 equivalents (CO
We performed a national economic impact analysis for petroleum product producers. All petroleum product refiners will incur annual compliance costs of less than 1-percent of their sales. For all firms, the minimum cost-to-sales ratio is <0.01-percent; the maximum cost-to-sales ratio is 0.87-percent; and the mean cost-to-sales ratio is 0.03-percent. Therefore, the overall economic impact of this proposed rule should be minimal for the refining industry and its consumers.
In addition, the EPA performed a screening analysis for impacts on small businesses by comparing estimated annualized engineering compliance costs at the firm-level to firm sales. The screening analysis found that the ratio of compliance cost to firm revenue falls below 1-percent for the 28 small companies likely to be affected by the proposal. For small firms, the minimum cost-to-sales ratio is <0.01-percent; the maximum cost-to-sales ratio is 0.62-percent; and the mean cost-to-sales ratio is 0.07-percent.
More information and details of this analysis is provided in the technical document “Economic Impact Analysis for Petroleum Refineries Proposed Amendments to the National Emissions Standards for Hazardous Air Pollutants”, which is available in the docket for this rule (Docket ID No. EPA-HQ-OAR-2010-0682).
The final rule is anticipated to result in a reduction of 1,323 tpy of HAP (based on allowable emissions under the MACT standards) and 16,660 tpy of VOC, not including potential emission reductions that may occur as a result of the operating and monitoring requirements for flares and fugitive emission sources via fenceline monitoring. These avoided emissions will result in improvements in air quality and reduced negative health effects associated with exposure to air pollution of these emissions; however, we have not quantified or monetized the benefits of reducing these emissions for this rulemaking.
To examine the potential impacts on vulnerable populations (minority, low-income and indigenous communities) that might be associated with the Petroleum Refinery source categories addressed in this final rule, we evaluated the percentages of various social, demographic and economic groups in the at-risk populations living near the facilities where these sources are located and compared them to national averages. Our analysis of the demographics of the population with estimated risks greater than 1-in-1 million indicates potential disparities in risks between demographic groups including the African American, Other and Multiracial, Hispanic, Below the Poverty Level, and Over 25 without a High School Diploma when compared to the nationwide percentages of those groups. These groups will benefit the most from the emission reductions achieved by this final rulemaking, which is projected to result in 1 million fewer people exposed to risks greater than 1-in-1 million.
Additionally, these communities will benefit from this rulemaking, as this rulemaking for the first time ever requires fenceline monitoring, and reporting of fenceline data. The agency during the pre-proposal period and
Under Executive Order 13045 the EPA must evaluate the effects of the planned regulation on children's health and safety. This action's health and risk assessments are contained in section IV.A of this preamble. We believe we have adequately estimated risk for children, and we do not believe that the environmental health risks addressed by this action present a disproportionate risk to children. When the EPA derives exposure reference concentrations and unit risk estimates (URE) for HAP, it also considers the most sensitive populations identified (
This action is an economically significant regulatory action that was submitted to the Office of Management and Budget (OMB) for review. Any changes made in response to OMB recommendations have been documented in the docket. The EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis, “Economic Impact Analysis: Petroleum Refineries—Final Amendments to the National Emissions Standards for Hazardous Air Pollutants and New Source Performance Standards” is available in Docket ID Number EPA-HQ-OAR-2010-0682.
The information collection requirements in this rule have been submitted for approval to the Office of Management and Budget (OMB) under the
Adequate recordkeeping and reporting are necessary to ensure compliance with these standards as required by the CAA. The ICR information collected from recordkeeping and reporting requirements is also used for prioritizing inspections and is of sufficient quality to be used as evidence in court.
The ICR document prepared by the EPA for the amendments to the Petroleum Refinery MACT standards for 40 CFR part 63, subpart CC has been assigned the EPA ICR number 1692.08. Burden changes associated with these amendments would result from new monitoring, recordkeeping and reporting requirements. The estimated annual increase in recordkeeping and reporting burden hours is 99,722 hours; the frequency of response is quarterly and semiannual for reports for all respondents that must comply with the rule's reporting requirements; and the estimated average number of likely respondents per year is 95 (this is the average in the second year). The cost burden to respondents resulting from the collection of information includes the total capital cost annualized over the equipment's expected useful life (about $18 million, which includes monitoring equipment for fenceline monitoring, pressure relief devices, and flares), a total operation and maintenance component (about $21 million per year for fenceline and flare monitoring), and a labor cost component (about $8.3 million per year, the cost of the additional 99,722 labor hours). Burden is defined at 5 CFR 1320.3(b).
The ICR document prepared by the EPA for the amendments to the Petroleum Refinery MACT standards for 40 CFR part 63, subpart UUU has been assigned the EPA ICR number 1844.06. Burden changes associated with these amendments would result from new testing, recordkeeping and reporting requirements being finalized with this action. The estimated average burden per response is 25 hours; the frequency of response ranges from annually up to every 5 years for respondents that have FCCU, and the estimated average number of likely respondents per year is 67. The cost burden to respondents resulting from the collection of information includes the performance testing costs (approximately $778,000 per year over the first 3 years for the initial PM and one-time HCN performance tests and $235,000 per year starting in the fourth year), and a labor cost component (approximately $410,000 per year for 4,940 additional labor hours). Burden is defined at 5 CFR 1320.3(b).
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is approved by OMB, the Agency will publish a technical amendment to 40 CFR part 9 in the
I certify that this action will not have a significant economic impact on a substantial number of small entities (SISNOSE) under the RFA. The small entities subject to the requirements of this action are small businesses, small organizations and small governmental jurisdictions. For purposes of assessing the impacts of this rule on small entities, a small entity is defined as: (1) A small business in the petroleum refining industry having 1,500 or fewer employees (Small Business Administration (SBA), 2011); (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field. Details of this analysis are presented in the economic impact analysis which can be found in the docket for this rule (Docket ID No. EPA-HQ-OAR-2010-0682).
This action does not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments. As discussed earlier in this preamble, these amendments result in nationwide costs of $63.2 million per year for the private sector. Additionally, the rule contains no requirements that apply to small
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 action does not have tribal implications, as specified in Executive Order 13175. The final amendments impose no requirements on tribal governments. Thus, Executive Order 13175 does not apply to this action. Consistent with the EPA Policy on Consultation and Coordination with Indian Tribes, the EPA consulted with tribal officials during the development of the proposed rule and specifically solicited comment on the proposed amendments from tribal officials.
This action is not subject to Executive Order 13045 because the EPA does not believe the environmental health or safety risks addressed by this action present a disproportionate risk to children. This action's health and risk assessments are contained in section IV.A of this preamble.
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 overall economic impact of this final rule should be minimal for the refining industry and its consumers.
This rulemaking involves technical standards. Therefore, the EPA conducted searches for the Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards through the Enhanced National Standards Systems Network (NSSN) Database managed by the American National Standards Institute (ANSI). We also contacted voluntary consensus standards (VCS) organizations and accessed and searched their databases. We conducted searches for EPA Methods 18, 22, 320, 325A, and 325B of 40 CFR parts 60 and 63, appendix A. No applicable VCS were identified for EPA Method 22.
The following voluntary consensus standards were identified as acceptable alternatives to the EPA test methods for the purpose of this rule.
The voluntary consensus standard ISO 16017-2:2003(E) “Air quality—Sampling and analysis of volatile organic compounds in ambient air, indoor air and workplace air by sorbent tube/thermal desorption/capillary gas chromatography. Part 2: Diffusive sampling” is an acceptable alternative to Method 325A, Sections 1.2, 6.1 and 6.5 and Method 325B Sections 1.3, 7.1.2, 7.1.3, 7.1.4, 12.2.4, 13.0, A.1.1, and A.2. This voluntary consensus standard gives general guidance for the sampling and analysis of volatile organic compounds in air. It is applicable to indoor, ambient and workplace air. This standard is available at International Organization for Standardization, ISO Central Secretariat, Chemin de Blandonnet 8, CP 401, 1214 Vernier, Geneva, Switzerland. See
The voluntary consensus standard BS EN 14662-4:2005 “Ambient Air Quality: Standard Method for the Measurement of Benzene Concentrations—Part 4: Diffusive Sampling Followed By Thermal Desorption and Gas Chromatography” is an acceptable alternative to Method 325A, Section 1.2 and Method 325B, Sections 1.3, 7.1.3, 7.1.4, 12.2.4, 13.0, A.1.1, and A.2. This voluntary consensus standard gives general guidance for the sampling and analysis of benzene in air by diffusive sampling, thermal desorption and capillary gas chromatography. This standard is available the European Committee for Standardization, Avenue Marnix 17—B-1000 Brussels. See
The voluntary consensus standard ASTM D6420-99 (2010) “Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography/Mass Spectrometry” is an acceptable alternative to EPA Method 18. This voluntary consensus standard employs a direct interface gas chromatography/mass spectrometer (GCMS) to identify and quantify a list of 36 volatile organic compounds (the compounds are listed in the method).
The voluntary consensus standard ASTM D6196-03 (Reapproved 2009) “Standard Practice for Selection of Sorbents, Sampling, and Thermal Desorption Analysis Procedures for Volatile Organic Compounds in Air” is an acceptable alternative to Method 325A, Sections 1.2 and 6.1, and Method 325B, Sections 1.3, 7.1.2, 7.1.3, 7.1.4, 13.0, A.1.1, and A.2. This voluntary consensus standard is intended to assist in the selection of sorbents and procedures for the sampling and analysis of ambient, indoor, and workplace atmospheres for a variety of common volatile organic compounds.
The voluntary consensus standards ASTM D1945-03 and later revision ASTM D1945-14 “Standard Test Method for Analysis of Natural Gas by Gas Chromatography” are acceptable for natural gas analysis. This voluntary consensus standard covers the determination of the chemical composition of natural gases and similar gaseous mixtures. This test method may be abbreviated for the analysis of lean natural gases containing negligible amounts of hexanes and higher hydrocarbons, or for the determination of one or more components, as required.
The voluntary consensus standard ASTM UOP539-12 “Refinery Gas Analysis by GC” is acceptable for refinery gas analysis. This voluntary consensus standard is for determining the composition of refinery gas streams or vaporized liquefied petroleum gas using a preconfigured, commercially available gas chromatograph.
The voluntary consensus standard ASTM D6348-03 (Reapproved 2010) including Annexes A1 through A8, “Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform (FTIR) Spectroscopy” is an acceptable alternative to EPA Method 320. This voluntary consensus standard is a field test method that employs an extractive sampling system to direct stationary source effluent to an FTIR spectrometer for the identification and quantification of gaseous compounds. This field test method provides near real time analysis of extracted gas samples from stationary sources.
The voluntary consensus standard ASTM D6348-12e1 “Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform (FTIR) Spectroscopy” is an acceptable alternative to EPA Method 320 with the following two caveats: (1) The test plan preparation and implementation in the Annexes to ASTM D 6348-03 (Reapproved 2010), Sections A1 through A8 are mandatory; and (2) In ASTM D6348-03 (Reapproved 2010) Annex A5 (Analyte Spiking Technique), the percent (%) R must be determined for each target analyte (Equation A5.5). In order for the test data to be acceptable for a compound, %R must be 70% ≥ R ≤ 130%. If the %R value does not meet this criterion for a target compound, the test data is not acceptable for that compound and the test must be repeated
This voluntary consensus standard is a field test method that employs an extractive sampling system to direct stationary source effluent to an FTIR spectrometer for the identification and quantification of gaseous compounds. This field test method provides near real time analysis of extracted gas samples from stationary sources.
The EPA solicited comments on VCS and invited the public to identify potentially-applicable VCS; however, we did not receive comments regarding this aspect of 40 CFR part 60, subparts J and Ja, and part 63, subparts CC, UUU, and Y. Under 40 CFR 63.7(f) and 63.8(f), a source may apply to the EPA for permission to use alternative test methods or alternative monitoring requirements in place of any required testing methods, performance specifications, or procedures in this final rule.
Executive Order 12898 (59 FR 7629; February 16, 1994) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies and activities on minority populations and low-income populations in the U.S. The EPA defines environmental justice as the fair treatment and meaningful involvement of all people regardless of race, color, national origin or income with respect to the development, implementation and enforcement of environmental laws, regulations and policies. The EPA has this goal for all communities and persons by working to ensure that everyone enjoys the same degree of protection from environmental and health hazards and equal access to the decision-making process to have a healthy environment in which to live, learn and work.
The EPA believes the human health or environmental risk addressed by this action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations. As discussed in section V.D. of this preamble, the EPA conducted an analysis of the characteristics of the population with greater than 1-in-1 million risk living within 50 km of the 142 refineries affected by this rulemaking and determined that there are more African-Americans, Other and multiracial groups, Hispanics, low-income individuals, individuals with less than a high school diploma compared to national averages. Therefore, these populations are expected to experience the benefits of the risk reductions associated with this rule. The results of this evaluation are contained in two technical reports, “Risk and Technology Review—Analysis of Socio-Economic Factors for Populations Living Near Petroleum Refineries”, available in the docket for this action (See Docket ID Nos. EPA-HQ-OAR-2010-0682-0226 and -0227). Additionally, a discussion of the final risk analysis is included in Sections IV.A and V.D of this preamble.
The EPA has determined that this final rule will not have disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations because it maintains or increases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any minority, low-income or indigenous populations. Further, the EPA believes that implementation of this rule will provide an ample margin of safety to protect public health of all demographic groups.
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. This action is a “major rule” as defined by 5 U.S.C. 804(2).
Environmental protection, Administrative practice and procedures, Air pollution control, Hazardous substances, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements.
Environmental protection, Administrative practice and procedures, Air pollution control, Hazardous substances, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements.
For the reasons stated in the preamble, title 40, chapter I, of the Code of Federal Regulations is amended as follows:
42 U.S.C. 7401
(b) * * *
(1) * * *
(iv) The supporting test results from sampling the requested fuel gas stream/system demonstrating that the sulfur content is less than 5 ppmv. Sampling data must include, at minimum, 2 weeks of daily monitoring (14 grab samples) for frequently operated fuel gas streams/systems; for infrequently operated fuel gas streams/systems, seven grab samples must be collected unless other additional information would support reduced sampling. The owner or operator shall use detector tubes (“length-of-stain tube” type measurement) following the “Gas Processors Association Standard 2377-86 (incorporated by reference—see § 60.17), using tubes with a maximum span between 10 and 40 ppmv inclusive when 1≤N≤10, where N = number of pump strokes, to test the applicant fuel gas stream for H
(3) * * *
(iii) If the operation change results in a sulfur content that is outside the range of concentrations included in the original application and the owner or operator chooses not to submit new information to support an exemption, the owner or operator must begin H
(b) Except for flares and delayed coking units, the provisions of this subpart apply only to affected facilities under paragraph (a) of this section which either commence construction, modification or reconstruction after May 14, 2007, or elect to comply with the provisions of this subpart in lieu of complying with the provisions in subpart J of this part. * * *
The revision and addition read as follows:
(b) * * *
(1) * * *
(i) 1.0 gram per kilogram (g/kg) (1 pound (lb) per 1,000 lb) coke burn-off or, if a PM continuous emission monitoring system (CEMS) is used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 percent excess air for each modified or reconstructed FCCU.
(iii) 1.0 g/kg (1 lb/1,000 lb) coke burn-off or, if a PM CEMS is used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 percent excess air for each affected FCU.
(f) Except as provided in paragraph (f)(3) of this section, each owner or operator of an affected sulfur recovery plant shall comply with the applicable emission limits in paragraph (f)(1) or (2) of this section.
(1) For a sulfur recovery plant with a design production capacity greater than 20 long tons per day (LTD), the owner or operator shall comply with the applicable emission limit in paragraph (f)(1)(i) or (ii) of this section. If the sulfur recovery plant consists of multiple process trains or release points, the owner or operator shall comply with the applicable emission limit for each process train or release point individually or comply with the applicable emission limit in paragraph (f)(1)(i) or (ii) as a flow rate weighted average for a group of release points from the sulfur recovery plant provided that flow is monitored as specified in § 60.106a(a)(7); if flow is not monitored as specified in § 60.106a(a)(7), the owner or operator shall comply with the applicable emission limit in paragraph (f)(1)(i) or (ii) for each process train or release point individually. For a sulfur recovery plant with a design production capacity greater than 20 long LTD and a reduction control system not followed by incineration, the owner or operator shall also comply with the H
(i) For a sulfur recovery plant with an oxidation control system or a reduction control system followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere (SO
(ii) For a sulfur recovery plant with a reduction control system not followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere containing reduced sulfur compounds in excess of the emission limit calculated using Equation 1 of this section. For Claus units that use only ambient air in the Claus burner or for non-Claus sulfur recovery plants, this reduced sulfur compounds emission limit is 300 ppmv calculated as ppmv SO
(iii) For a sulfur recovery plant with a reduction control system not followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere containing hydrogen sulfide (H
(2) For a sulfur recovery plant with a design production capacity of 20 LTD or less, the owner or operator shall comply with the applicable emission limit in paragraph (f)(2)(i) or (ii) of this section. If the sulfur recovery plant consists of multiple process trains or release points, the owner or operator may comply with the applicable emission limit for each process train or release point individually or comply with the applicable emission limit in paragraph (f)(2)(i) or (ii) as a flow rate weighted average for a group of release points from the sulfur recovery plant provided that flow is monitored as specified in § 60.106a(a)(7); if flow is not monitored as specified in § 60.106a(a)(7), the owner or operator shall comply with the applicable emission limit in paragraph (f)(2)(i) or (ii) for each process train or release point individually. For a sulfur recovery plant with a design production capacity of 20 LTD or less and a reduction control system not followed by incineration, the owner or operator shall also comply with the H
(i) For a sulfur recovery plant with an oxidation control system or a reduction control system followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere containing SO
(ii) For a sulfur recovery plant with a reduction control system not followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere containing reduced sulfur compounds in excess of the emission limit calculated using Equation 2 of this section. For Claus units that use only ambient air in the Claus burner or for non-Claus sulfur recovery plants, this reduced sulfur compounds emission limit is 3,000 ppmv calculated as ppmv SO
(iii) For a sulfur recovery plant with a reduction control system not followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere containing H
(3) The emission limits in paragraphs (f)(1) and (2) of this section shall not apply during periods of maintenance of the sulfur pit, which shall not exceed 240 hours per year. The owner or operator must document the time periods during which the sulfur pit vents were not controlled and measures taken to minimize emissions during these periods. Examples of these measures include not adding fresh sulfur or shutting off vent fans.
(g) * * *
(1) Except as provided in (g)(1)(iii) of this section, for each fuel gas combustion device, the owner or operator shall comply with either the emission limit in paragraph (g)(1)(i) of this section or the fuel gas concentration limit in paragraph (g)(1)(ii) of this section. For CO boilers or furnaces that are part of a fluid catalytic cracking unit or fluid coking unit affected facility, the owner or operator shall comply with the fuel gas concentration limit in paragraph (g)(1)(ii) for all fuel gas streams combusted in these units.
The revisions and additions read as follows:
(a) The owner or operator shall conduct a performance test for each FCCU, FCU, sulfur recovery plant and fuel gas combustion device to demonstrate initial compliance with each applicable emissions limit in § 60.102a and conduct a performance test for each flare to demonstrate initial compliance with the H
(b) The owner or operator of a FCCU or FCU that elects to monitor control device operating parameters according to the requirements in § 60.105a(b), to use bag leak detectors according to the requirements in § 60.105a(c), or to use COMS according to the requirements in § 60.105a(e) shall conduct a PM performance test at least annually (
(f) The owner or operator of an FCCU or FCU that uses cyclones to comply with the PM per coke burn-off emissions limit in § 60.102a(b)(1) shall establish a site-specific opacity operating limit according to the procedures in paragraphs (f)(1) through (3) of this section.
(h) The owner or operator shall determine compliance with the SO
(6) If oxygen or oxygen-enriched air is used in the Claus burner and either Equation 1 or 2 of this subpart is used to determine the applicable emissions limit, determine the average O
The revisions and additions read as follows:
(b) * * *
(1) * * *
(i) For units controlled using an electrostatic precipitator, the owner or operator shall use CPMS to measure and record the hourly average total power input and secondary current to the entire system.
(ii) * * *
(A) As an alternative to pressure drop, the owner or operator of a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles must conduct a daily check of the air or water pressure to the spray nozzles and record the results of each check. Faulty (
(2) For use in determining the coke burn-off rate for an FCCU or FCU, the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring the concentrations of CO
(i) The owner or operator shall install, operate, and maintain each CO
(ii) The owner or operator shall conduct performance evaluations of each CO
(iii) If a CO monitor is required, the owner or operator shall install, operate, and maintain each CO monitor according to Performance Specification 4 or 4A of appendix B to this part. If this CO monitor also serves to demonstrate compliance with the CO emissions limit in § 60.102a(b)(4), the span value for this instrument is 1,000 ppm; otherwise, the span value for this instrument should be set at approximately 2 times the typical CO concentration expected in the FCCU of FCU flue gas prior to any emission control or energy recovery system that burns auxiliary fuels.
(iv) If a CO monitor is required, the owner or operator shall conduct performance evaluations of each CO monitor according to the requirements in § 60.13(c) and Performance Specification 4 of appendix B to this part. The owner or operator shall use Method 10, 10A, or 10B of appendix A-3 to this part for conducting the relative accuracy evaluations.
(v) The owner or operator shall comply with the quality assurance requirements of procedure 1 of appendix F to this part, including quarterly accuracy determinations for CO
(h) * * *
(1) The owner or operator shall install, operate, and maintain each CO monitor according to Performance Specification 4 or 4A of appendix B to this part. The span value for this instrument is 1,000 ppmv CO.
(3) * * *
(i) The demonstration shall consist of continuously monitoring CO emissions for 30 days using an instrument that meets the requirements of Performance Specification 4 or 4A of appendix B to this part. The span value shall be 100 ppmv CO instead of 1,000 ppmv, and the relative accuracy limit shall be 10 percent of the average CO emissions or 5 ppmv CO, whichever is greater. For instruments that are identical to Method 10 of appendix A-4 to this part and employ the sample conditioning system of Method 10A of appendix A-4 to this part, the alternative relative accuracy test procedure in section 10.1 of Performance Specification 2 of appendix B to this part may be used in place of the relative accuracy test.
(i) * * *
(1) If a CPMS is used according to paragraph (b)(1) of this section, all 3-hour periods during which the average PM control device operating characteristics, as measured by the continuous monitoring systems under paragraph (b)(1), fall below the levels established during the performance test. If the alternative to pressure drop CPMS is used for the owner or operator of a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles, each day in which abnormal pressure readings are not corrected within 12 hours of identification.
(2) If a bag leak detection system is used according to paragraph (c) of this section, each day in which the cause of an alarm is not alleviated within the time period specified in paragraph (c)(3) of this section.
(7) All 1-hour periods during which the average CO concentration as measured by the CO continuous monitoring system under paragraph (h) of this section exceeds 500 ppmv or, if applicable, all 1-hour periods during which the average temperature and O
The revisions and additions read as follows:
(a) * * *
(1) * * *
(i) The span value for the SO
(iv) The owner or operator shall install, operate, and maintain each O
(v) The span value for the O
(vi) The owner or operator shall conduct performance evaluations for the O
(vii) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to this part for each monitor, including annual accuracy determinations for each O
(2) For sulfur recovery plants that are subject to the reduced sulfur compounds emission limit in § 60.102a(f)(1)(ii) or (f)(2)(ii), the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of reduced sulfur compounds and O
(i) The span value for the reduced sulfur compounds monitor is two times the applicable reduced sulfur compounds emission limit as SO
(ii) The owner or operator shall install, operate, and maintain each reduced sulfur compounds CEMS according to Performance Specification 5 of appendix B to this part.
(iii) The owner or operator shall conduct performance evaluations of each reduced sulfur compounds monitor according to the requirements in § 60.13(c) and Performance Specification 5 of appendix B to this part. * * *
(3) In place of the reduced sulfur compounds monitor required in paragraph (a)(2) of this section, the owner or operator may install, calibrate, operate, and maintain an instrument using an air or O
(i) The span value for this monitor is two times the applicable reduced sulfur compounds emission limit as SO
(4) For sulfur recovery plants that are subject to the H
(i) The span value for this monitor is two times the applicable H
(ii) The owner or operator shall install, operate, and maintain each H
(iii) The owner or operator shall conduct performance evaluations for each H
(iv) The owner or operator shall install, operate, and maintain each O
(v) The span value for the O
(vi) The owner or operator shall conduct performance evaluations for the O
(vii) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to this part for each monitor, including annual accuracy determinations for each O
(5) For sulfur recovery plants that use oxygen or oxygen enriched air in the Claus burner and that elects to monitor O
(i) The owner or operator shall install, operate, and maintain each O
(ii) The span value for the O
(iii) The owner or operator shall conduct performance evaluations for the O
(iv) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to this part for each monitor, including annual accuracy determinations for each O
(v) The owner or operator shall use the hourly average O
(6) As an alternative to the O
(i) The owner or operator shall install, calibrate, operate and maintain each flow monitor according to the manufacturer's procedures and specifications and the following requirements.
(A) Locate the monitor in a position that provides a representative measurement of the total gas flow rate.
(B) Use a flow sensor meeting an accuracy requirement of ±5 percent over the normal range of flow measured or 10 cubic feet per minute, whichever is greater.
(C) Use a flow monitor that is maintainable online, is able to continuously correct for temperature, pressure and, for ambient air flow monitor, moisture content, and is able to record dry flow in standard conditions (as defined in § 60.2) over one-minute averages.
(D) At least quarterly, perform a visual inspection of all components of the monitor for physical and operational integrity and all electrical connections for oxidation and galvanic corrosion if the flow monitor is not equipped with a redundant flow sensor.
(E) Recalibrate the flow monitor in accordance with the manufacturer's procedures and specifications biennially (every two years) or at the frequency specified by the manufacturer.
(ii) The owner or operator shall use 20.9 percent as the oxygen content of the ambient air.
(iii) The owner or operator shall use product specifications (
(iv) The owner or operator shall calculate the hourly average O
(v) The owner or operator shall use the hourly average O
(7) Owners or operators of a sulfur recovery plant that elects to comply with the SO
(i) The owner or operator shall install, calibrate, operate and maintain each flow monitor according to the manufacturer's procedures and specifications and the following requirements.
(A) Locate the monitor in a position that provides a representative measurement of the total gas flow rate.
(B) Use a flow sensor meeting an accuracy requirement of ±5 percent over the normal range of flow measured or 10 cubic feet per minute, whichever is greater.
(C) Use a flow monitor that is maintainable online, is able to continuously correct for temperature, pressure, and moisture content, and is able to record dry flow in standard conditions (as defined in § 60.2) over one-minute averages.
(D) At least quarterly, perform a visual inspection of all components of the monitor for physical and operational integrity and all electrical connections for oxidation and galvanic corrosion if the flow monitor is not equipped with a redundant flow sensor.
(E) Recalibrate the flow monitor in accordance with the manufacturer's procedures and specifications biennially (every two years) or at the frequency specified by the manufacturer.
(ii) The owner or operator shall correct the flow to 0 percent excess air using Equation 11 of this section:
(iii) The owner or operator shall calculate the flow weighted average SO
(iv) For sulfur recovery plants that use oxygen or oxygen enriched air in the Claus burner, the owner or operator shall use Equation 10 of this section and the hourly emission limits determined in paragraph (a)(5)(v) or (a)(6)(v) of this section in-place of the pollutant concentration to determine the flow weighted average hourly emission limit for each hour. The allowable emission limit shall be calculated as the arithmetic average of 12 contiguous 1-hour averages (
(b) * * *
(2) All 12-hour periods during which the average concentration of reduced sulfur compounds (as SO
(3) All 12-hour periods during which the average concentration of H
(a) * * *
(1) * * *
(i) The owner or operator shall install, operate, and maintain each SO
(ii) The owner or operator shall conduct performance evaluations for the SO
(b) * * *
(1) * * *
(iv) The supporting test results from sampling the requested fuel gas stream/system demonstrating that the sulfur content is less than 5 ppmv H
(3) * * *
(iii) If the operation change results in a sulfur content that is outside the range of concentrations included in the original application and the owner or operator chooses not to submit new information to support an exemption, the owner or operator must begin H
(d) * * *
(3) As an alternative to the requirements in paragraph (d)(2) of this section, the owner or operator of a gas-fired process heater shall install, operate and maintain a gas composition analyzer and determine the average F factor of the fuel gas using the factors in Table 1 of this subpart and Equation 13 of this section. If a single fuel gas system provides fuel gas to several process heaters, the F factor may be determined at a single location in the fuel gas system provided it is representative of the fuel gas fed to the affected process heater(s).
X
MEV
MHC
1,000,000 = unit conversion, Btu per MMBtu.
(e) * * *
(1)
(ii) The owner or operator shall conduct performance evaluations of each total reduced sulfur monitor according to the requirements in § 60.13(c) and Performance Specification 5 of appendix B to this part. The owner or operator of each total
(2)
(ii) The owner or operator shall conduct performance evaluations of each H
(vi) * * *
(C) Determine the acceptable range for subsequent weekly samples based on the 95-percent confidence interval for the distribution of daily ratios based on the 10 individual daily ratios using Equation 14 of this section.
AR = Acceptable range of subsequent ratio determinations, unitless.
Ratio
2.262 = t-distribution statistic for 95-percent 2-sided confidence interval for 10 samples (9 degrees of freedom).
SDev = Standard deviation of the 10 daily average total sulfur-to-H
(3)
TS
C
F
HHV
(f) * * *
(1) * * *
(ii) Use a flow sensor meeting an accuracy requirement of ±20 percent of the flow rate at velocities ranging from 0.1 to 1 feet per second and an accuracy of ±5 percent of the flow rate for velocities greater than 1 feet per second.
(h) * * *
(5)
42 U.S.C. 7401
The revisions and additions read as follows:
(h) * * *
(14) ASTM D1945-03 (Reapproved 2010), Standard Test Method for Analysis of Natural Gas by Gas Chromatography, Approved January 1, 2010, IBR approved for §§ 63.670(j), 63.772(h), and 63.1282(g).
(15) ASTM D1945-14, Standard Test Method for Analysis of Natural Gas by Gas Chromatography, Approved
(74) ASTM D6196-03 (Reapproved 2009), Standard Practice for Selection of Sorbents, Sampling, and Thermal Desorption Analysis Procedures for Volatile Organic Compounds in Air, Approved March 1, 2009, IBR approved for appendix A to this part: Method 325A and Method 325B.
(78) ASTM D6348-03 (Reapproved 2010), Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, including Annexes A1 through A8, Approved October 1, 2010, IBR approved for § 63.1571(a), tables 4 and 5 to subpart JJJJJ, tables 4 and 6 to subpart KKKKK, tables 1, 2, and 5 to subpart UUUUU and appendix B to subpart UUUUU.
(79) ASTM D6348-12e1, Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, Approved February 1, 2012, IBR approved for § 63.1571(a).
(85) ASTM D6420-99 (Reapproved 2010), Standard Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography-Mass Spectrometry, Approved October 1, 2010, IBR approved for § 63.670(j) and appendix A to this part: Method 325B.
(104) ASTM UOP539-12, Refinery Gas Analysis by GC, Copyright 2012 (to UOP), IBR approved for § 63.670(j).
(j) * * *
(2) BS EN 14662-4:2005, Ambient air quality standard method for the measurement of benzene concentrations—Part 4: Diffusive sampling followed by thermal desorption and gas chromatography, Published June 27, 2005, IBR approved for appendix A to this part: Method 325A and Method 325B.
(m) * * *
(2) EPA-454/B-08-002, Office of Air Quality Planning and Standards (OAQPS), Quality Assurance Handbook for Air Pollution Measurement Systems, Volume IV: Meteorological Measurements, Version 2.0 (Final), March 24, 2008, IBR approved for § 63.658(d) and appendix A to this part: Method 325A.
(4) EPA-454/R-99-005, Office of Air Quality Planning and Standards (OAQPS), Meteorological Monitoring Guidance for Regulatory Modeling Applications, February 2000, IBR approved for appendix A to this part: Method 325A.
(n) * * *
(3) ISO 16017-2:2003(E): Indoor, ambient and workplace air—sampling and analysis of volatile organic compounds by sorbent tube/thermal desorption/capillary gas chromatography—Part 2: Diffusive sampling, May 15, 2003, IBR approved for appendix A to this part: Method 325A and Method 325B.
(s) * * *
(1) “Air Stripping Method (Modified El Paso Method) for Determination of Volatile Organic Compound Emissions from Water Sources,” Revision Number One, dated January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, January 31, 2003, IBR approved for §§ 63.654(c) and (g), 63.655(i), and 63.11920.
(a) * * *
(4) Existing sources with emissions less than 10 and 25 tons must meet the submerged fill standards of 46 CFR 153.282.
The revisions and additions read as follows:
(a) This subpart applies to petroleum refining process units and to related emissions points that are specified in paragraphs (c)(1) through (9) of this section that are located at a plant site and that meet the criteria in paragraphs (a)(1) and (2) of this section:
(c) For the purposes of this subpart, the affected source shall comprise all emissions points, in combination, listed in paragraphs (c)(1) through (9) of this section that are located at a single refinery plant site.
(9) All releases associated with the decoking operations of a delayed coking unit, as defined in this subpart.
(d) * * *
(5) Emission points routed to a fuel gas system, as defined in § 63.641, provided that on and after January 30, 2019, any flares receiving gas from that fuel gas system are subject to § 63.670. No other testing, monitoring, recordkeeping, or reporting is required for refinery fuel gas systems or emission points routed to refinery fuel gas systems.
(h) Sources subject to this subpart are required to achieve compliance on or before the dates specified in table 11 of this subpart, except as provided in paragraphs (h)(1) through (3) of this section.
(1) Marine tank vessels at existing sources shall be in compliance with this subpart, except for §§ 63.657 through 63.660, no later than August 18, 1999, unless the vessels are included in an emissions average to generate emission credits. Marine tank vessels used to generate credits in an emissions average shall be in compliance with this subpart no later than August 18, 1998, unless an extension has been granted by the Administrator as provided in § 63.6(i).
(2) Existing Group 1 floating roof storage vessels meeting the applicability criteria in item 1 of the definition of Group 1 storage vessel shall be in compliance with § 63.646 at the first degassing and cleaning activity after August 18, 1998, or August 18, 2005, whichever is first.
(3) An owner or operator may elect to comply with the provisions of § 63.648(c) through (i) as an alternative to the provisions of § 63.648(a) and (b). In such cases, the owner or operator shall comply no later than the dates specified in paragraphs (h)(3)(i) through (iii) of this section.
(i) Phase I (see table 2 of this subpart), beginning on August 18, 1998;
(ii) Phase II (see table 2 of this subpart), beginning no later than August 18, 1999; and
(iii) Phase III (see table 2 of this subpart), beginning no later than February 18, 2001.
(k) * * *
(1) The reconstructed source, addition, or change shall be in compliance with the new source requirements in item (1), (2), or (3) of table 11 of this subpart, as applicable, upon initial startup of the reconstructed source or by August 18, 1995, whichever is later; and
(l) If an additional petroleum refining process unit is added to a plant site or if a miscellaneous process vent, storage vessel, gasoline loading rack, marine tank vessel loading operation, heat exchange system, or decoking operation that meets the criteria in paragraphs (c)(1) through (9) of this section is added to an existing petroleum refinery or if another deliberate operational process change creating an additional Group 1 emissions point(s) (as defined in § 63.641) is made to an existing petroleum refining process unit, and if the addition or process change is not subject to the new source requirements as determined according to paragraph (i) or (j) of this section, the requirements in paragraphs (l)(1) through (4) of this section shall apply. Examples of process changes include, but are not limited to, changes in production capacity, or feed or raw material where the change requires construction or physical alteration of the existing equipment or catalyst type, or whenever there is replacement, removal, or addition of recovery equipment. For purposes of this paragraph (l) and paragraph (m) of this section, process changes do not include: Process upsets, unintentional temporary process changes, and changes that are within the equipment configuration and operating conditions documented in the Notification of Compliance Status report required by § 63.655(f).
(2) The added emission point(s) and any emission point(s) within the added or changed petroleum refining process unit shall be in compliance with the applicable requirements in item (4) of table 11 of this subpart by the dates specified in paragraph (l)(2)(i) or (ii) of this section.
(i) If a petroleum refining process unit is added to a plant site or an emission point(s) is added to any existing petroleum refining process unit, the added emission point(s) shall be in compliance upon initial startup of any added petroleum refining process unit or emission point(s) or by the applicable compliance date in item (4) of table 11 of this subpart, whichever is later.
(3) The owner or operator of a petroleum refining process unit or of a storage vessel, miscellaneous process vent, wastewater stream, gasoline loading rack, marine tank vessel loading operation, heat exchange system, or decoking operation meeting the criteria in paragraphs (c)(1) through (9) of this section that is added to a plant site and is subject to the requirements for existing sources shall comply with the reporting and recordkeeping requirements that are applicable to existing sources including, but not limited to, the reports listed in paragraphs (l)(3)(i) through (vii) of this section. A process change to an existing petroleum refining process unit shall be subject to the reporting requirements for existing sources including, but not limited to, the reports listed in paragraphs (l)(3)(i) through (vii) of this section. The applicable reports include, but are not limited to:
(m) If a change that does not meet the criteria in paragraph (l) of this section is made to a petroleum refining process unit subject to this subpart, and the change causes a Group 2 emission point to become a Group 1 emission point (as defined in § 63.641), then the owner or operator shall comply with the applicable requirements of this subpart for existing sources, as specified in item (4) of table 11 of this subpart, for the Group 1 emission point as expeditiously as practicable, but in no event later than 3 years after the emission point becomes Group 1.
(n) Overlap of this subpart with other regulations for storage vessels. As applicable, paragraphs (n)(1), (3), (4), (6), and (7) of this section apply for Group 2 storage vessels and paragraphs (n)(2) and (5) of this section apply for Group 1 storage vessels.
(1) After the compliance dates specified in paragraph (h) of this section, a Group 2 storage vessel that is subject to the provisions of 40 CFR part 60, subpart Kb, is required to comply only with the requirements of 40 CFR part 60, subpart Kb, except as provided in paragraph (n)(8) of this section. After the compliance dates specified in paragraph (h) of this section, a Group 2 storage vessel that is subject to the provisions of 40 CFR part 61, subpart Y, is required to comply only with the requirements of 40 CFR part 61, subpart Y, except as provided in paragraph (n)(10) of this section.
(2) After the compliance dates specified in paragraph (h) of this section, a Group 1 storage vessel that is also subject to 40 CFR part 60, subpart Kb, is required to comply only with either 40 CFR part 60, subpart Kb, except as provided in paragraph (n)(8) of this section or this subpart. After the compliance dates specified in paragraph (h) of this section, a Group 1 storage vessel that is also subject to 40 CFR part 61, subpart Y, is required to comply only with either 40 CFR part 61, subpart Y, except as provided in paragraph (n)(10) of this section or this subpart.
(3) After the compliance dates specified in paragraph (h) of this section, a Group 2 storage vessel that is part of a new source and is subject to 40 CFR 60.110b, but is not required to apply controls by 40 CFR 60.110b or 60.112b, is required to comply only with this subpart.
(4) After the compliance dates specified in paragraph (h) of this section, a Group 2 storage vessel that is part of a new source and is subject to 40 CFR 61.270, but is not required to apply controls by 40 CFR 61.271, is required to comply only with this subpart.
(5) After the compliance dates specified in paragraph (h) of this section, a Group 1 storage vessel that is also subject to the provisions of 40 CFR part 60, subpart K or Ka, is required to only comply with the provisions of this subpart.
(8) Storage vessels described by paragraph (n)(1) of this section are to comply with 40 CFR part 60, subpart Kb, except as provided in paragraphs (n)(8)(i) through (vi) of this section. Storage vessels described by paragraph (n)(2) electing to comply with part 60, subpart Kb of this chapter shall comply with subpart Kb except as provided in paragraphs (n)(8)(i) through (viii) of this section.
(ii) If the owner or operator determines that it is unsafe to perform the seal gap measurements required in § 60.113b(b) of this chapter or to inspect the vessel to determine compliance with
(vii) To be in compliance with § 60.112b(a)(1)(iv) or (a)(2)(ii) of this chapter, guidepoles in floating roof storage vessels must be equipped with covers and/or controls (
(viii) If a flare is used as a control device for a storage vessel, on and after January 30, 2019, the owner or operator must meet the requirements of § 63.670 instead of the requirements referenced from part 60, subpart Kb of this chapter for that flare.
(9) * * *
(i) If the owner or operator determines that it is unsafe to perform the seal gap measurements required in § 60.113a(a)(1) of this chapter because the floating roof appears to be structurally unsound and poses an imminent danger to inspecting personnel, the owner or operator shall comply with the requirements in either § 63.120(b)(7)(i) or (ii) of subpart G (only up to the compliance date specified in paragraph (h) of this section for compliance with § 63.660, as applicable) or either § 63.1063(c)(2)(iv)(A) or (B) of subpart WW.
(10) Storage vessels described by paragraph (n)(1) of this section are to comply with 40 CFR part 61, subpart Y, except as provided in paragraphs (n)(10)(i) through (vi) of this section. Storage vessels described by paragraph (n)(2) electing to comply with 40 CFR part 61, subpart Y, shall comply with subpart Y except as provided for in paragraphs (n)(10)(i) through (viii) of this section.
(i) Storage vessels that are to comply with § 61.271(b) of this chapter are exempt from the secondary seal requirements of § 61.271(b)(2)(ii) of this chapter during the gap measurements for the primary seal required by § 61.272(b) of this chapter.
(ii) If the owner or operator determines that it is unsafe to perform the seal gap measurements required in § 61.272(b) of this chapter or to inspect the vessel to determine compliance with § 61.272(a) of this chapter because the roof appears to be structurally unsound and poses an imminent danger to inspecting personnel, the owner or operator shall comply with the requirements in either § 63.120(b)(7)(i) or (ii) of subpart G (only up to the compliance date specified in paragraph (h) of this section for compliance with § 63.660, as applicable) or either § 63.1063(c)(2)(iv)(A) or (B) of subpart WW.
(iii) If a failure is detected during the inspections required by § 61.272(a)(2) of this chapter or during the seal gap measurements required by § 61.272(b)(1) of this chapter, and the vessel cannot be repaired within 45 days and the vessel cannot be emptied within 45 days, the owner or operator may utilize up to two extensions of up to 30 additional calendar days each. The owner or operator is not required to provide a request for the extension to the Administrator.
(iv) If an extension is utilized in accordance with paragraph (n)(10)(iii) of this section, the owner or operator shall, in the next periodic report, identify the vessel, provide the information listed in § 61.272(a)(2) or (b)(4)(iii) of this chapter, and describe the nature and date of the repair made or provide the date the storage vessel was emptied.
(v) Owners and operators of storage vessels complying with 40 CFR part 61, subpart Y, may submit the inspection reports required by § 61.275(a), (b)(1), and (d) of this chapter as part of the periodic reports required by this subpart, rather than within the 60-day period specified in § 61.275(a), (b)(1), and (d) of this chapter.
(vi) The reports of rim seal inspections specified in § 61.275(d) of this chapter are not required if none of the measured gaps or calculated gap areas exceed the limitations specified in § 61.272(b)(4) of this chapter. Documentation of the inspections shall be recorded as specified in § 61.276(a) of this chapter.
(vii) To be in compliance with § 61.271(a)(6) or (b)(3) of this chapter, guidepoles in floating roof storage vessels must be equipped with covers and/or controls (
(viii) If a flare is used as a control device for a storage vessel, on and after January 30, 2019, the owner or operator must meet the requirements of § 63.670 instead of the requirements referenced from part 61, subpart Y of this chapter for that flare.
(o) * * *
(2) * * *
(i) Comply with paragraphs (o)(2)(i)(A) through (D) of this section.
(D) If a flare is used as a control device, on and after January 30, 2019, the flare shall meet the requirements of § 63.670. Prior to January 30, 2019, the flare shall meet the applicable requirements of 40 CFR part 61, subpart FF, and subpart G of this part, or the requirements of § 63.670.
(ii) Comply with paragraphs (o)(2)(ii)(A) through (C) of this section.
(C) If a flare is used as a control device, on and after January 30, 2019, the flare shall meet the requirements of § 63.670. Prior to January 30, 2019, the flare shall meet the applicable requirements of 40 CFR part 61, subpart FF, and subpart G of this part, or the requirements of § 63.670.
(s) Overlap of this subpart with other regulation for flares. On January 30, 2019, flares that are subject to the provisions of 40 CFR 60.18 or 63.11 and subject to this subpart are required to comply only with the provisions specified in this subpart. Prior to January 30, 2019, flares that are subject to the provisions of 40 CFR 60.18 or 63.11 and elect to comply with the requirements in §§ 63.670 and 63.671 are required to comply only with the provisions specified in this subpart.
The revisions and additions read as follows:
(1) Prior to February 1, 2016:
(i) A storage vessel at an existing source that has a design capacity greater than or equal to 177 cubic meters and stored-liquid maximum true vapor pressure greater than or equal to 10.4 kilopascals and stored-liquid annual average true vapor pressure greater than or equal to 8.3 kilopascals and annual average HAP liquid concentration greater than 4 percent by weight total organic HAP;
(ii) A storage vessel at a new source that has a design storage capacity greater than or equal to 151 cubic meters and stored-liquid maximum true vapor pressure greater than or equal to 3.4 kilopascals and annual average HAP liquid concentration greater than 2 percent by weight total organic HAP; or
(iii) A storage vessel at a new source that has a design storage capacity greater than or equal to 76 cubic meters and less than 151 cubic meters and stored-
(2) On and after February 1, 2016:
(i) A storage vessel at an existing source that has a design capacity greater than or equal to 151 cubic meters (40,000 gallons) and stored-liquid maximum true vapor pressure greater than or equal to 5.2 kilopascals (0.75 pounds per square inch) and annual average HAP liquid concentration greater than 4 percent by weight total organic HAP;
(ii) A storage vessel at an existing source that has a design storage capacity greater than or equal to 76 cubic meters (20,000 gallons) and less than 151 cubic meters (40,000 gallons) and stored-liquid maximum true vapor pressure greater than or equal to 13.1 kilopascals (1.9 pounds per square inch) and annual average HAP liquid concentration greater than 4 percent by weight total organic HAP;
(iii) A storage vessel at a new source that has a design storage capacity greater than or equal to 151 cubic meters (40,000 gallons) and stored-liquid maximum true vapor pressure greater than or equal to 3.4 kilopascals (0.5 pounds per square inch) and annual average HAP liquid concentration greater than 2 percent by weight total organic HAP; or
(iv) A storage vessel at a new source that has a design storage capacity greater than or equal to 76 cubic meters (20,000 gallons) and less than 151 cubic meters (40,000 gallons) and stored-liquid maximum true vapor pressure greater than or equal to 13.1 kilopascals (1.9 pounds per square inch) and annual average HAP liquid concentration greater than 2 percent by weight total organic HAP.
(1) Gaseous streams routed to a fuel gas system, provided that on and after January 30, 2019, any flares receiving gas from the fuel gas system are in compliance with § 63.670;
(2) Pressure relief device discharges;
(3) Leaks from equipment regulated under § 63.648;
(4) [Reserved]
(5) In situ sampling systems (onstream analyzers) until January 30, 2019. After this date, these sampling systems will be included in the definition of miscellaneous process vents;
(6) Catalytic cracking unit catalyst regeneration vents;
(7) Catalytic reformer regeneration vents;
(8) Sulfur plant vents;
(9) Vents from control devices such as scrubbers, boilers, incinerators, and electrostatic precipitators applied to catalytic cracking unit catalyst regeneration vents, catalytic reformer regeneration vents, and sulfur plant vents;
(10) Vents from any stripping operations applied to comply with the wastewater provisions of this subpart, subpart G of this part, or 40 CFR part 61, subpart FF;
(11) Emissions associated with delayed coking unit decoking operations;
(12) Vents from storage vessels;
(13) Emissions from wastewater collection and conveyance systems including, but not limited to, wastewater drains, sewer vents, and sump drains; and
(14) Hydrogen production plant vents through which carbon dioxide is removed from process streams or through which steam condensate produced or treated within the hydrogen plant is degassed or deaerated.
(1) For Group 1 storage vessels complying with § 63.660:
(i) An internal floating roof, including an external floating roof converted to an internal floating roof, meeting the specifications of § 63.1063(a)(1)(i) and (b);
(ii) An external floating roof meeting the specifications of § 63.1063(a)(1)(ii), (a)(2), and (b); or
(iii) [Reserved]
(iv) A closed-vent system to a control device that reduces organic HAP emissions by 95 percent, or to an outlet concentration of 20 parts per million by volume (ppmv).
(v) For purposes of emissions averaging, these four technologies are considered equivalent.
(2) For all other storage vessels:
(i) An internal floating roof meeting the specifications of § 63.119(b) of subpart G except for § 63.119(b)(5) and (6);
(ii) An external floating roof meeting the specifications of § 63.119(c) of subpart G except for § 63.119(c)(2);
(iii) An external floating roof converted to an internal floating roof meeting the specifications of § 63.119(d) of subpart G except for § 63.119(d)(2); or
(iv) A closed-vent system to a control device that reduces organic HAP emissions by 95 percent, or to an outlet concentration of 20 parts per million by volume.
(v) For purposes of emissions averaging, these four technologies are considered equivalent.
The revisions and additions read as follows:
(b) The emission standards set forth in this subpart shall apply at all times.
(d) * * *
(3) Performance tests shall be conducted according to the provisions of § 63.7(e) except that performance tests shall be conducted at maximum representative operating capacity for the process. During the performance test, an owner or operator shall operate the control device at either maximum or minimum representative operating conditions for monitored control device parameters, whichever results in lower emission reduction. An owner or operator shall not conduct a performance test during startup, shutdown, periods when the control device is bypassed or periods when the process, monitoring equipment or control device is not operating properly. The owner/operator may not conduct performance tests during periods of malfunction. The owner or operator must record the process information that is necessary to document operating conditions during the test and include in such record an explanation to support that the test was conducted at maximum representative operating capacity. Upon request, the owner or operator shall make available to the Administrator such records as may be necessary to determine the conditions of performance tests.
(e) All applicable records shall be maintained as specified in § 63.655(i).
(i) The owner or operator of an existing source shall demonstrate compliance with the emission standard in paragraph (g) of this section by following the procedures specified in paragraph (k) of this section for all emission points, or by following the emissions averaging compliance approach specified in paragraph (l) of this section for specified emission points and the procedures specified in paragraph (k)(1) of this section.
(k) The owner or operator of an existing source may comply, and the owner or operator of a new source shall comply, with the applicable provisions in §§ 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651, as specified in § 63.640(h).
(1) The owner or operator using this compliance approach shall also comply with the requirements of §§ 63.648 and/or 63.649, 63.654, 63.655, 63.657, 63.658, 63.670 and 63.671, as applicable.
(l) The owner or operator of an existing source may elect to control some of the emission points within the source to different levels than specified under §§ 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651, as applicable according to § 63.640(h), by using an emissions averaging compliance approach as long as the overall emissions for the source do not exceed the emission level specified in paragraph (g) of this section. The owner or operator using emissions averaging shall meet the requirements in paragraphs (l)(1) and (2) of this section.
(2) Comply with the requirements of §§ 63.648 and/or 63.649, 63.654, 63.652, 63.653, 63.655, 63.657, 63.658, 63.670 and 63.671, as applicable.
(n) At all times, the owner or operator must operate and maintain any affected source, including associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices for minimizing emissions. The general duty to minimize emissions does not require the owner operator to make any further efforts to reduce emissions if levels required by the applicable standard have been achieved. Determination of whether a source is operating in compliance with operation and maintenance requirements will be based on information available to the Administrator which may include, but is not limited to, monitoring results, review of operation and maintenance procedures, review of operation and maintenance records, and inspection of the source.
(a) The owner or operator of a Group 1 miscellaneous process vent as defined in § 63.641 shall comply with the requirements of either paragraph (a)(1) or (2) of this section or, if applicable, paragraph (c) of this section. The owner or operator of a miscellaneous process vent that meets the conditions in paragraph (c) of this section is only required to comply with the requirements of paragraph (c) of this section and § 63.655(g)(13) and (i)(12) for that vent.
(1) Reduce emissions of organic HAP's using a flare. On and after January 30, 2019, the flare shall meet the requirements of § 63.670. Prior to January 30, 2019, the flare shall meet the requirements of § 63.11(b) of subpart A or the requirements of § 63.670.
(c) An owner or operator may designate a process vent as a maintenance vent if the vent is only used as a result of startup, shutdown, maintenance, or inspection of equipment where equipment is emptied, depressurized, degassed or placed into service. The owner of operator does not need to designate a maintenance vent as a Group 1 or Group 2 miscellaneous process vent. The owner or operator must comply with the applicable requirements in paragraphs (c)(1) through (3) of this section for each maintenance vent.
(1) Prior to venting to the atmosphere, process liquids are removed from the equipment as much as practical and the equipment is depressured to a control device, fuel gas system, or back to the process until one of the following conditions, as applicable, is met.
(i) The vapor in the equipment served by the maintenance vent has a lower
(ii) If there is no ability to measure the LEL of the vapor in the equipment based on the design of the equipment, the pressure in the equipment served by the maintenance vent is reduced to 5 psig or less. Upon opening the maintenance vent, active purging of the equipment cannot be used until the LEL of the vapors in the maintenance vent (or inside the equipment if the maintenance is a hatch or similar type of opening) equipment is less than 10 percent.
(iii) The equipment served by the maintenance vent contains less than 72 pounds of VOC.
(iv) If the maintenance vent is associated with equipment containing pyrophoric catalyst (
(2) Except for maintenance vents complying with the alternative in paragraph (c)(1)(iii) of this section, the owner or operator must determine the LEL or, if applicable, equipment pressure using process instrumentation or portable measurement devices and follow procedures for calibration and maintenance according to manufacturer's specifications.
(3) For maintenance vents complying with the alternative in paragraph (c)(1)(iii) of this section, the owner or operator shall determine mass of VOC in the equipment served by the maintenance vent based on the equipment size and contents after considering any contents drained or purged from the equipment. Equipment size may be determined from equipment design specifications. Equipment contents may be determined using process knowledge.
(a) Except as provided in paragraph (b) of this section, each owner or operator of a Group 1 miscellaneous process vent that uses a combustion device to comply with the requirements in § 63.643(a) shall install the monitoring equipment specified in paragraph (a)(1), (2), (3), or (4) of this section, depending on the type of combustion device used. All monitoring equipment shall be installed, calibrated, maintained, and operated according to manufacturer's specifications or other written procedures that provide adequate assurance that the equipment will monitor accurately and, except for CPMS installed for pilot flame monitoring, must meet the applicable minimum accuracy, calibration and quality control requirements specified in table 13 of this subpart.
(2) Where a flare is used prior to January 30, 2019, a device (including but not limited to a thermocouple, an ultraviolet beam sensor, or an infrared sensor) capable of continuously detecting the presence of a pilot flame is required, or the requirements of § 63.670 shall be met. Where a flare is used on and after January 30, 2019, the requirements of § 63.670 shall be met.
(c) The owner or operator of a Group 1 miscellaneous process vent using a vent system that contains bypass lines that could divert a vent stream away from the control device used to comply with paragraph (a) of this section either directly to the atmosphere or to a control device that does not comply with the requirements in § 63.643(a) shall comply with either paragraph (c)(1) or (2) of this section. Use of the bypass at any time to divert a Group 1 miscellaneous process vent stream to the atmosphere or to a control device that does not comply with the requirements in § 63.643(a) is an emissions standards violation. Equipment such as low leg drains and equipment subject to § 63.648 are not subject to this paragraph (c).
(1) Install, calibrate and maintain a flow indicator that determines whether a vent stream flow is present at least once every hour. A manual block valve equipped with a valve position indicator may be used in lieu of a flow indicator, as long as the valve position indicator is monitored continuously. Records shall be generated as specified in § 63.655(h) and (i). The flow indicator shall be installed at the entrance to any bypass line that could divert the vent stream away from the control device to the atmosphere; or
(2) Secure the bypass line valve in the non-diverting position with a car-seal or a lock-and-key type configuration. A visual inspection of the seal or closure mechanism shall be performed at least once every month to ensure that the valve is maintained in the non-diverting position and that the vent stream is not diverted through the bypass line.
(e) * * *
(1) Methods 1 or 1A of 40 CFR part 60, appendix A-1, as appropriate, shall be used for selection of the sampling site. For vents smaller than 0.10 meter in diameter, sample at the center of the vent.
(f) * * *
(2) The gas volumetric flow rate shall be determined using Methods 2, 2A, 2C, 2D, or 2F of 40 CFR part 60, appendix A-1 or Method 2G of 40 CFR part 60, appendix A-2, as appropriate.
Upon a demonstration of compliance with the standards in § 63.660 by the compliance dates specified in § 63.640(h), the standards in this section shall no longer apply.
(b) * * *
(2) When an owner or operator and the Administrator do not agree on whether the annual average weight percent organic HAP in the stored liquid is above or below 4 percent for a storage vessel at an existing source or above or below 2 percent for a storage vessel at a new source, an appropriate method (based on the type of liquid stored) as published by EPA or a consensus-based standards organization shall be used. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373,
The revisions and additions read as follows:
(a) Except as provided in paragraphs (b) and (c) of this section, each owner or operator of a Group 1 wastewater stream shall comply with the requirements of §§ 61.340 through 61.355 of this chapter for each process wastewater stream that meets the definition in § 63.641.
(c) If a flare is used as a control device, on and after January 30, 2019, the flare shall meet the requirements of § 63.670. Prior to January 30, 2019, the flare shall meet the applicable requirements of part 61, subpart FF of this chapter, or the requirements of § 63.670.
The revisions and additions read as follows:
(a) * * *
(3) If a flare is used as a control device, on and after January 30, 2019, the flare shall meet the requirements of § 63.670. Prior to January 30, 2019, the flare shall meet the applicable requirements of part 60, subpart VV of this chapter, or the requirements of § 63.670.
(c) In lieu of complying with the existing source provisions of paragraph (a) in this section, an owner or operator may elect to comply with the requirements of §§ 63.161 through 63.169, 63.171, 63.172, 63.175, 63.176, 63.177, 63.179, and 63.180 of subpart H except as provided in paragraphs (c)(1) through (12) and (e) through (i) of this section.
(11) [Reserved]
(12) If a flare is used as a control device, on and after January 30, 2019, the flare shall meet the requirements of § 63.670. Prior to January 30, 2019, the flare shall meet the applicable requirements of §§ 63.172 and 63.180, or the requirements of § 63.670.
(j) Except as specified in paragraph (j)(4) of this section, the owner or operator must comply with the requirements specified in paragraphs (j)(1) and (2) of this section for pressure relief devices, such as relief valves or rupture disks, in organic HAP gas or vapor service instead of the pressure relief device requirements of § 60.482-4 or § 63.165, as applicable. Except as specified in paragraphs (j)(4) and (5) of this section, the owner or operator must also comply with the requirements specified in paragraph (j)(3) of this section for all pressure relief devices.
(1)
(2)
(i) If the pressure relief device does not consist of or include a rupture disk, conduct instrument monitoring, as specified in § 60.485(b) or § 63.180(c), as applicable, no later than 5 calendar days after the pressure relief device returns to organic HAP gas or vapor service following a pressure release to verify that the pressure relief device is operating with an instrument reading of less than 500 ppm.
(ii) If the pressure relief device includes a rupture disk, either comply with the requirements in paragraph (j)(2)(i) of this section (not replacing the rupture disk) or install a replacement disk as soon as practicable after a pressure release, but no later than 5 calendar days after the pressure release. The owner or operator must conduct instrument monitoring, as specified in § 60.485(b) or § 63.180(c), as applicable, no later than 5 calendar days after the pressure relief device returns to organic HAP gas or vapor service following a pressure release to verify that the pressure relief device is operating with an instrument reading of less than 500 ppm.
(iii) If the pressure relief device consists only of a rupture disk, install a replacement disk as soon as practicable after a pressure release, but no later than 5 calendar days after the pressure release. The owner or operator may not initiate startup of the equipment served by the rupture disk until the rupture disc is replaced. The owner or operator must conduct instrument monitoring, as specified in § 60.485(b) or § 63.180(c), as applicable, no later than 5 calendar days after the pressure relief device returns to organic HAP gas or vapor service following a pressure release to verify that the pressure relief device is operating with an instrument reading of less than 500 ppm.
(3)
(i) The owner or operator must equip each affected pressure relief device with a device(s) or use a monitoring system that is capable of:
(A) Identifying the pressure release;
(B) Recording the time and duration of each pressure release; and
(C) Notifying operators immediately that a pressure release is occurring. The device or monitoring system may be either specific to the pressure relief device itself or may be associated with the process system or piping, sufficient to indicate a pressure release to the atmosphere. Examples of these types of devices and systems include, but are not limited to, a rupture disk indicator, magnetic sensor, motion detector on the pressure relief valve stem, flow monitor, or pressure monitor.
(ii) The owner or operator must apply at least three redundant prevention measures to each affected pressure relief device and document these measures. Examples of prevention measures include:
(A) Flow, temperature, level and pressure indicators with deadman switches, monitors, or automatic actuators.
(B) Documented routine inspection and maintenance programs and/or operator training (maintenance programs and operator training may count as only one redundant prevention measure).
(C) Inherently safer designs or safety instrumentation systems.
(D) Deluge systems.
(E) Staged relief system where initial pressure relief valve (with lower set release pressure) discharges to a flare or other closed vent system and control device.
(iii) If any affected pressure relief device releases to atmosphere as a result of a pressure release event, the owner or operator must perform root cause analysis and corrective action analysis according to the requirement in paragraph (j)(6) of this section and implement corrective actions according to the requirements in paragraph (j)(7) of this section. The owner or operator must also calculate the quantity of organic HAP released during each pressure
(iv) The owner or operator shall determine the total number of release events occurred during the calendar year for each affected pressure relief device separately. The owner or operator shall also determine the total number of release events for each pressure relief device for which the root cause analysis concluded that the root cause was a
(v) Except for pressure relief devices described in paragraphs (j)(4) and (5) of this section, the following release events are a violation of the pressure release management work practice standards.
(A) Any release event for which the root cause of the event was determined to be operator error or poor maintenance.
(B) A second release event not including
(C) A third release event not including
(4)
(5)
(i) Pressure relief devices in heavy liquid service, as defined in § 63.641.
(ii) Pressure relief devices that only release material that is liquid at standard conditions (1 atmosphere and 68 degrees Fahrenheit) and that are hard-piped to a controlled drain system (
(iii) Thermal expansion relief valves.
(iv) Pressure relief devices designed with a set relief pressure of less than 2.5 psig.
(v) Pressure relief devices that do not have the potential to emit 72 lbs/day or more of VOC based on the valve diameter, the set release pressure, and the equipment contents.
(vi) Pressure relief devices on mobile equipment.
(6)
(i) You may conduct a single root cause analysis and corrective action analysis for a single emergency event that causes two or more pressure relief devices installed on the same equipment to release.
(ii) You may conduct a single root cause analysis and corrective action analysis for a single emergency event that causes two or more pressure relief devices to release, regardless of the equipment served, if the root cause is reasonably expected to be a force majeure event, as defined in this subpart.
(iii) Except as provided in paragraphs (j)(6)(i) and (ii) of this section, if more than one pressure relief device has a release during the same time period, an initial root cause analysis shall be conducted separately for each pressure relief device that had a release. If the initial root cause analysis indicates that the release events have the same root cause(s), the initially separate root cause analyses may be recorded as a single root cause analysis and a single corrective action analysis may be conducted.
(7)
(i) All corrective action(s) must be implemented within 45 days of the event for which the root cause and corrective action analyses were required or as soon thereafter as practicable. If an owner or operator concludes that no corrective action should be implemented, the owner or operator shall record and explain the basis for that conclusion no later than 45 days following the event.
(ii) For corrective actions that cannot be fully implemented within 45 days following the event for which the root cause and corrective action analyses were required, the owner or operator shall develop an implementation schedule to complete the corrective action(s) as soon as practicable.
(iii) No later than 45 days following the event for which a root cause and corrective action analyses were required, the owner or operator shall record the corrective action(s) completed to date, and, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates.
(c) * * *
(6) * * *
(i) * * *
(a) Except as provided in paragraphs (b) through (d) of this section, each owner or operator of a Group 1 gasoline loading rack classified under Standard Industrial Classification code 2911 located within a contiguous area and under common control with a petroleum refinery shall comply with subpart R of this part, §§ 63.421, 63.422(a) through (c) and (e), 63.425(a) through (c) and (e) through (i), 63.427(a) and (b), and 63.428(b), (c), (g)(1), (h)(1) through (3), and (k).
(d) If a flare is used as a control device, on and after January 30, 2019, the flare shall meet the requirements of § 63.670. Prior to January 30, 2019, the flare shall meet the applicable requirements of subpart R of this part, or the requirements of § 63.670.
(a) Except as provided in paragraphs (b) through (e) of this section, each owner or operator of a marine tank vessel loading operation located at a petroleum refinery shall comply with the requirements of §§ 63.560 through 63.568.
(d) The compliance time of 4 years after promulgation of 40 CFR part 63, subpart Y, does not apply. The compliance time is specified in § 63.640(h)(1).
(e) If a flare is used as a control device, on and after January 30, 2019, the flare shall meet the requirements of § 63.670. Prior to January 30, 2019, the flare shall meet the applicable requirements of subpart Y of this part, or the requirements of § 63.670.
The revisions and additions read as follows:
(a) This section applies to owners or operators of existing sources who seek to comply with the emission standard in § 63.642(g) by using emissions averaging according to § 63.642(l) rather than following the provisions of §§ 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651. Existing marine tank vessel loading operations located at the Valdez Marine Terminal source may not comply with the standard by using emissions averaging.
(g) * * *
(2) * * *
(iii) * * *
(B) * * *
(1) The percent reduction shall be measured according to the procedures in § 63.116 of subpart G if a combustion control device is used. For a flare meeting the criteria in § 63.116(a) of subpart G or § 63.670, as applicable, or a boiler or process heater meeting the criteria in § 63.645(d) or § 63.116(b) of subpart G, the percentage of reduction shall be 98 percent. If a noncombustion control device is used, percentage of reduction shall be demonstrated by a performance test at the inlet and outlet of the device, or, if testing is not feasible, by a control design evaluation and documented engineering calculations.
(h) * * *
(3) Emissions from storage vessels shall be determined as specified in § 63.150(h)(3) of subpart G, except as follows:
(i) For storage vessels complying with § 63.646:
(A) All references to § 63.119(b) in § 63.150(h)(3) of subpart G shall be replaced with: § 63.119(b) or § 63.119(b) except for § 63.119(b)(5) and (6).
(B) All references to § 63.119(c) in § 63.150(h)(3) of subpart G shall be replaced with: § 63.119(c) or § 63.119(c) except for § 63.119(c)(2).
(C) All references to § 63.119(d) in § 63.150(h)(3) of subpart G shall be replaced with: § 63.119(d) or § 63.119(d) except for § 63.119(d)(2).
(ii) For storage vessels complying with § 63.660:
(A) Section 63.1063(a)(1)(i), (a)(2), and (b) or § 63.1063(a)(1)(i) and (b) shall apply instead of § 63.119(b) in § 63.150(h)(3) of subpart G.
(B) Section 63.1063(a)(1)(ii), (a)(2), and (b) shall apply instead of § 63.119(c) in § 63.150(h)(3) of subpart G.
(C) Section 63.1063(a)(1)(i), (a)(2), and (b) or § 63.1063(a)(1)(i) and (b) shall apply instead of § 63.119(d) in § 63.150(h)(3) of subpart G.
(k) The owner or operator shall demonstrate that the emissions from the emission points proposed to be included in the average will not result in greater hazard or, at the option of the State or local permitting authority, greater risk to human health or the environment than if the emission points were controlled according to the provisions in §§ 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651, as applicable.
(3) An emissions averaging plan that does not demonstrate an equivalent or lower hazard or risk to the satisfaction of the State or local permitting authority shall not be approved. The State or local permitting authority may require such adjustments to the emissions averaging plan as are necessary in order to ensure that the average will not result in greater hazard or risk to human health or the environment than would result if the emission points were controlled according to §§ 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651, as applicable.
(a) For each emission point included in an emissions average, the owner or operator shall perform testing, monitoring, recordkeeping, and reporting equivalent to that required for Group 1 emission points complying with §§ 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651, as applicable. The specific requirements for miscellaneous process vents, storage vessels, wastewater, gasoline loading racks, and marine tank vessels are identified in paragraphs (a)(1) through (7) of this section.
(3) * * *
(i) Perform the monitoring or inspection procedures in § 63.646 and either § 63.120 of subpart G or § 63.1063 of subpart WW, as applicable; and
(ii) For closed vent systems with control devices, conduct an initial design evaluation as specified in § 63.646 and either § 63.120(d) of subpart G or § 63.985(b) of subpart SS, as applicable.
(7) If an emission point in an emissions average is controlled using a pollution prevention measure or a device or technique for which no monitoring parameters or inspection procedures are specified in §§ 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651, as applicable, the owner or operator shall establish a site-specific monitoring parameter and shall submit the information specified in § 63.655(h)(4) in the Implementation Plan.
The revisions and additions read as follows:
(f) Each owner or operator of a source subject to this subpart shall submit a Notification of Compliance Status report within 150 days after the compliance dates specified in § 63.640(h) with the exception of Notification of Compliance Status reports submitted to comply with § 63.640(l)(3) and for storage vessels subject to the compliance schedule specified in § 63.640(h)(2). Notification of Compliance Status reports required by § 63.640(l)(3) and for storage vessels subject to the compliance dates specified in § 63.640(h)(2) shall be submitted according to paragraph (f)(6) of this section. This information may be submitted in an operating permit application, in an amendment to an operating permit application, in a separate submittal, or in any combination of the three. If the required information has been submitted before the date 150 days after the compliance date specified in § 63.640(h), a separate Notification of Compliance Status report is not required within 150 days after the compliance dates specified in § 63.640(h). If an owner or operator submits the information specified in paragraphs (f)(1) through (5) of this section at different times, and/or in different submittals, later submittals may refer to earlier submittals instead of duplicating and resubmitting the previously submitted information. Each owner or operator of a gasoline loading rack classified under Standard Industrial Classification Code 2911 located within a contiguous area and under common control with a petroleum refinery subject to the standards of this subpart shall submit the Notification of Compliance Status report required by subpart R of this part within 150 days after the compliance dates specified in § 63.640(h).
(1) The Notification of Compliance Status report shall include the information specified in paragraphs (f)(1)(i) through (viii) of this section.
(i) * * *
(A) Identification of each storage vessel subject to this subpart, and for each Group 1 storage vessel subject to this subpart, the information specified in paragraphs (f)(1)(i)(A)(
(
(
(B) If a closed vent system and a control device other than a flare is used to comply with § 63.646 or § 63.660, the owner or operator shall submit:
(
(D) * * *
(
(iv) For miscellaneous process vents controlled by flares, initial compliance test results including the information in paragraphs (f)(1)(iv)(A) and (B) of this section.
(A) All visible emission readings, heat content determinations, flow rate measurements, and exit velocity determinations made during the compliance determination required by §§ 63.645 and 63.116(a) of subpart G or § 63.670(h), as applicable; and
(vii) For pressure relief devices in organic HAP service subject to the requirements in § 63.648(j)(3)(i) and (ii), this report shall include the information specified in paragraphs (f)(1)(vii)(A) and (B) of this section.
(A) A description of the monitoring system to be implemented, including the relief devices and process parameters to be monitored, and a description of the alarms or other methods by which operators will be notified of a pressure release.
(B) A description of the prevention measures to be implemented for each affected pressure relief device.
(viii) For each delayed coking unit, identification of whether the unit is an existing affected source or a new affected source and whether monitoring will be conducted as specified in § 63.657(b) or (c).
(2) If initial performance tests are required by §§ 63.643 through 63.653, the Notification of Compliance Status report shall include one complete test report for each test method used for a particular source. On and after February 1, 2016, performance tests shall be submitted according to paragraph (h)(9) of this section.
(3) For each monitored parameter for which a range is required to be established under § 63.120(d) of subpart G or § 63.985(b) of subpart SS for storage vessels or § 63.644 for miscellaneous process vents, the Notification of Compliance Status report shall include the information in paragraphs (f)(3)(i) through (iii) of this section.
(6) Notification of Compliance Status reports required by § 63.640(l)(3) and for storage vessels subject to the compliance dates specified in § 63.640(h)(2) shall be submitted no later than 60 days after the end of the 6-month period during which the change or addition was made that resulted in the Group 1 emission point or the existing Group 1 storage vessel was brought into compliance, and may be combined with the periodic report. * * *
(g) The owner or operator of a source subject to this subpart shall submit Periodic Reports no later than 60 days after the end of each 6-month period when any of the information specified in paragraphs (g)(1) through (7) of this section or paragraphs (g)(9) through (14) of this section is collected. The first 6-month period shall begin on the date the Notification of Compliance Status report is required to be submitted. A Periodic Report is not required if none of the events identified in paragraphs (g)(1)
(1) For storage vessels, Periodic Reports shall include the information specified for Periodic Reports in paragraphs (g)(2) through (5) of this section. Information related to gaskets, slotted membranes, and sleeve seals is not required for storage vessels that are part of an existing source complying with § 63.646.
(2)
(A) For vessels for which annual inspections are required under § 63.120(a)(2)(i) or (a)(3)(ii) of subpart G, the specifications and requirements listed in paragraphs (g)(2)(i)(A)(
(
(
(
(B) For vessels for which inspections are required under § 63.120(a)(2)(ii), (a)(3)(i), or (a)(3)(iii) of subpart G (
(
(
(ii) An owner or operator who elects to comply with § 63.660 by using a fixed roof and an internal floating roof shall submit the results of each inspection conducted in accordance with § 63.1063(c)(1), (d)(1), and (d)(2) of subpart WW in which a failure is detected in the control equipment. For vessels for which inspections are required under § 63.1063(c) and (d), the specifications and requirements listed in paragraphs (g)(2)(ii)(A) through (C) of this section apply.
(A) A failure is defined in § 63.1063(d)(1) of subpart WW.
(B) Each Periodic Report shall include a copy of the inspection record required by § 63.1065(b) of subpart WW when a failure occurs.
(C) An owner or operator who elects to use an extension in accordance with § 63.1063(e)(2) of subpart WW shall, in the next Periodic Report, submit the documentation required by § 63.1063(e)(2).
(3)
(A) The owner or operator shall submit, as part of the Periodic Report, documentation of the results of each seal gap measurement made in accordance with § 63.120(b) of subpart G in which the seal and seal gap requirements of § 63.120(b)(3), (4), (5), or (6) of subpart G are not met. This documentation shall include the information specified in paragraphs (g)(3)(i)(A)(
(
(
(
(
(B) If an extension is utilized in accordance with § 63.120(b)(7)(ii) or (b)(8) of subpart G, the owner or operator shall, in the next Periodic Report, identify the vessel; include the documentation specified in § 63.120(b)(7)(ii) or (b)(8) of subpart G, as applicable; and describe the date the vessel was emptied and the nature of and date the repair was made.
(C) The owner or operator shall submit, as part of the Periodic Report, documentation of any failures that are identified during visual inspections required by § 63.120(b)(10) of subpart G. This documentation shall meet the specifications and requirements in paragraphs (g)(3)(i)(C)(
(
(
(ii) An owner or operator who elects to comply with § 63.660 by using an external floating roof shall meet the periodic reporting requirements specified in paragraphs (g)(3)(ii)(A) and (B) of this section.
(A) For vessels for which inspections are required under § 63.1063(c)(2), (d)(1), and (d)(3) of subpart WW, the owner or operator shall submit, as part of the Periodic Report, a copy of the inspection record required by § 63.1065(b) of subpart WW when a failure occurs. A failure is defined in § 63.1063(d)(1).
(B) An owner or operator who elects to use an extension in accordance with § 63.1063(e)(2) or (c)(2)(iv)(B) of subpart WW shall, in the next Periodic Report, submit the documentation required by those paragraphs.
(4) [Reserved]
(5) An owner or operator who elects to comply with § 63.646 or § 63.660 by installing a closed vent system and control device shall submit, as part of the next Periodic Report, the information specified in paragraphs (g)(5)(i) through (v) of this section, as applicable.
(i) The Periodic Report shall include the information specified in paragraphs (g)(5)(i)(A) and (B) of this section for those planned routine maintenance operations that would require the control device not to meet the requirements of either § 63.119(e)(1) or (2) of subpart G, § 63.985(a) and (b) of subpart SS, or § 63.670, as applicable.
(A) A description of the planned routine maintenance that is anticipated to be performed for the control device during the next 6 months. This description shall include the type of maintenance necessary, planned frequency of maintenance, and lengths of maintenance periods.
(B) A description of the planned routine maintenance that was performed for the control device during the previous 6 months. This description shall include the type of maintenance performed and the total number of hours during those 6 months that the control device did not meet the requirements of either § 63.119(e)(1) or (2) of subpart G, § 63.985(a) and (b) of subpart SS, or § 63.670, as applicable, due to planned routine maintenance.
(ii) If a control device other than a flare is used, the Periodic Report shall describe each occurrence when the monitored parameters were outside of the parameter ranges documented in the Notification of Compliance Status report. The description shall include: Identification of the control device for which the measured parameters were outside of the established ranges, and causes for the measured parameters to be outside of the established ranges.
(iii) If a flare is used prior to January 30, 2019 and prior to electing to comply with the requirements in § 63.670, the Periodic Report shall describe each occurrence when the flare does not meet the general control device requirements specified in § 63.11(b) of subpart A and shall include: Identification of the flare that does not meet the general requirements specified in § 63.11(b) of subpart A, and reasons the flare did not meet the general requirements specified in § 63.11(b) of subpart A.
(iv) If a flare is used on or after the date for which compliance with the requirements in § 63.670 is elected, which can be no later than January 30, 2019, the Periodic Report shall include the items specified in paragraph (g)(11) of this section.
(v) An owner or operator who elects to comply with § 63.660 by installing an alternate control device as described in § 63.1064 of subpart WW shall submit, as part of the next Periodic Report, a written application as described in § 63.1066(b)(3) of subpart WW.
(6) * * *
(i) * * *
(D) For data compression systems under paragraph (h)(5)(iii) of this section, an operating day when the monitor operated for less than 75 percent of the operating hours or a day when less than 18 monitoring values were recorded.
(iii) For periods in closed vent systems when a Group 1 miscellaneous process vent stream was detected in the bypass line or diverted from the control device and either directly to the atmosphere or to a control device that does not comply with the requirements in § 63.643(a), report the date, time, duration, estimate of the volume of gas, the concentration of organic HAP in the gas and the resulting mass emissions of organic HAP that bypassed the control device. For periods when the flow indicator is not operating, report the date, time, and duration.
(7) * * *
(i) Results of the performance test shall include the identification of the source tested, the date of the test, the percentage of emissions reduction or outlet pollutant concentration reduction (whichever is needed to determine compliance) for each run and for the average of all runs, and the values of the monitored operating parameters.
(10) For pressure relief devices subject to the requirements § 63.648(j), Periodic Reports must include the information specified in paragraphs (g)(10)(i) through (iii) of this section.
(i) For pressure relief devices in organic HAP gas or vapor service, pursuant to § 63.648(j)(1), report any instrument reading of 500 ppm or greater.
(ii) For pressure relief devices in organic HAP gas or vapor service subject to § 63.648(j)(2), report confirmation that any monitoring required to be done during the reporting period to show compliance was conducted.
(iii) For pressure relief devices in organic HAP service subject to § 63.648(j)(3), report each pressure release to the atmosphere, including duration of the pressure release and estimate of the mass quantity of each organic HAP released, and the results of any root cause analysis and corrective action analysis completed during the reporting period, including the corrective actions implemented during the reporting period and, if applicable, the implementation schedule for planned corrective actions to be implemented subsequent to the reporting period.
(11) For flares subject to § 63.670, Periodic Reports must include the information specified in paragraphs (g)(11)(i) through (iv) of this section.
(i) Records as specified in paragraph (i)(9)(i) of this section for each 15-minute block during which there was at least one minute when regulated material is routed to a flare and no pilot flame is present.
(ii) Visible emission records as specified in paragraph (i)(9)(ii)(C) of this section for each period of 2 consecutive hours during which visible emissions exceeded a total of 5 minutes.
(iii) The 15-minute block periods for which the applicable operating limits specified in § 63.670(d) through (f) are not met. Indicate the date and time for the period, the net heating value operating parameter(s) determined following the methods in § 63.670(k) through (n) as applicable.
(iv) For flaring events meeting the criteria in § 63.670(o)(3):
(A) The start and stop time and date of the flaring event.
(B) The length of time for which emissions were visible from the flare during the event.
(C) The periods of time that the flare tip velocity exceeds the maximum flare tip velocity determined using the methods in § 63.670(d)(2) and the maximum 15-minute block average flare tip velocity recorded during the event.
(D) Results of the root cause and corrective actions analysis completed during the reporting period, including the corrective actions implemented during the reporting period and, if applicable, the implementation schedule for planned corrective actions to be implemented subsequent to the reporting period.
(12) For delayed coking units, the Periodic Report must include the information specified in paragraphs (g)(12)(i) through (iv) of this section.
(i) For existing source delayed coking units, any 60-cycle average exceeding the applicable limit in § 63.657(a)(1).
(ii) For new source delayed coking units, any direct venting event
(iii) The total number of double quenching events performed during the reporting period.
(iv) For each double quenching draining event when the drain water temperature exceeded 210 °F, report the drum, date, time, the coke drum vessel pressure or temperature, as applicable, when pre-vent draining was initiated, and the maximum drain water temperature during the pre-vent draining period.
(13) For maintenance vents subject to the requirements in § 63.643(c), Periodic Reports must include the information specified in paragraphs (g)(13)(i) through (iv) of this section for any release exceeding the applicable limits in § 63.643(c)(1). For the purposes of this reporting requirement, owners or operators complying with § 63.643(c)(1)(iv) must report each venting event for which the lower explosive limit is 20 percent or greater.
(i) Identification of the maintenance vent and the equipment served by the maintenance vent.
(ii) The date and time the maintenance vent was opened to the atmosphere.
(iii) The lower explosive limit, vessel pressure, or mass of VOC in the equipment, as applicable, at the start of atmospheric venting. If the 5 psig vessel pressure option in § 63.643(c)(1)(ii) was used and active purging was initiated while the lower explosive limit was 10 percent or greater, also include the lower explosive limit of the vapors at the time active purging was initiated.
(iv) An estimate of the mass of organic HAP released during the entire atmospheric venting event.
(14) Any changes in the information provided in a previous Notification of Compliance Status report.
(h) * * *
(2) For storage vessels, notifications of inspections as specified in paragraphs (h)(2)(i) and (ii) of this section.
(i) * * *
(B) Except as provided in paragraph (h)(2)(i)(C) of this section, if the internal inspection required by § 63.120(a)(2), (a)(3), or (b)(10) of subpart G or § 63.1063(d)(1) of subpart WW is not planned and the owner or operator could not have known about the inspection 30 calendar days in advance of refilling the vessel with organic HAP, the owner or operator shall notify the Administrator at least 7 calendar days prior to refilling of the storage vessel. Notification may be made by telephone and immediately followed by written documentation demonstrating why the inspection was unplanned. This notification, including the written documentation, may also be made in writing and sent so that it is received by the Administrator at least 7 calendar days prior to the refilling.
(ii) In order to afford the Administrator the opportunity to have an observer present, the owner or operator of a storage vessel equipped with an external floating roof shall notify the Administrator of any seal gap measurements. The notification shall be made in writing at least 30 calendar days in advance of any gap measurements required by § 63.120(b)(1) or (2) of subpart G or § 63.1062(d)(3) of subpart WW. The State or local permitting authority can waive this notification requirement for all or some storage vessels subject to the rule or can allow less than 30 calendar days' notice.
(5) * * *
(iii) An owner or operator may use an automated data compression recording system that does not record monitored operating parameter values at a set frequency (for example, once every hour) but records all values that meet set criteria for variation from previously recorded values.
(A) The system shall be designed to:
(
(
(
(
(
(B) You must maintain a record of the description of the monitoring system and data compression recording system including the criteria used to determine which monitored values are recorded and retained, the method for calculating daily averages, and a demonstrations that they system meets all criteria of paragraph (h)(5)(iii)(A) of this section.
(8) For fenceline monitoring systems subject to § 63.658, within 45 calendar days after the end of each quarterly reporting period covered by the periodic report, each owner or operator shall submit the following information to the EPA's Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can be accessed through the EPA's Central Data Exchange (CDX) (
(i) Individual sample results for each monitor for each sampling period during the quarterly reporting period. For the first reporting period and for any period in which a passive monitor is added or moved, the owner or operator shall report the coordinates of all of the passive monitor locations. The owner or operator shall determine the coordinates using an instrument with an accuracy of at least 3 meters. Coordinates shall be in decimal degrees with at least five decimal places.
(ii) The biweekly annual average concentration difference (Δc) values for benzene for the quarterly reporting period.
(iii) Notation for each biweekly value that indicates whether background correction was used, all measurements in the sampling period were below detection, or whether an outlier was removed from the sampling period data set.
(9) On and after February 1, 2016, if required to submit the results of a performance test or CEMS performance evaluation, the owner or operator shall submit the results according to the procedures in paragraphs (h)(9)(i) and (ii) of this section.
(i) Within 60 days after the date of completing each performance test as required by this subpart, the owner or operator shall submit the results of the performance tests following the procedure specified in either paragraph (h)(9)(i)(A) or (B) of this section.
(A) For data collected using test methods supported by the EPA's Electronic Reporting Tool (ERT) as listed on the EPA's ERT Web site (
(B) For data collected using test methods that are not supported by the EPA's ERT as listed on the EPA's ERT Web site at the time of the test, the owner or operator must submit the results of the performance test to the Administrator at the appropriate address listed in § 63.13.
(ii) Within 60 days after the date of completing each CEMS performance evaluation as required by this subpart, the owner or operator must submit the results of the performance evaluation following the procedure specified in either paragraph (h)(9)(ii)(A) or (B) of this section.
(A) For performance evaluations of continuous monitoring systems measuring relative accuracy test audit (RATA) pollutants that are supported by the EPA's ERT as listed on the EPA's ERT Web site at the time of the evaluation, the owner or operator must submit the results of the performance evaluation to the EPA via the CEDRI. (CEDRI can be accessed through the EPA's CDX.) Performance evaluation data must be submitted in a file format generated through the use of the EPA's ERT or an alternate file format consistent with the XML schema listed on the EPA's ERT Web site. If an owner or operator claims that some of the performance evaluation information being submitted is CBI, the owner or operator must submit a complete file generated through the use of the EPA's ERT or an alternate electronic file consistent with the XML schema listed on the EPA's ERT Web site, including information claimed to be CBI, on a compact disc, flash drive or other commonly used electronic storage media to the EPA. The electronic storage media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: Group Leader, Measurement Policy Group, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT or alternate file with the CBI omitted must be submitted to the EPA via the EPA's CDX as described earlier in this paragraph (h)(9)(ii)(A).
(B) For any performance evaluations of continuous monitoring systems measuring RATA pollutants that are not supported by the EPA's ERT as listed on the EPA's ERT Web site at the time of the evaluation, the owner or operator must submit the results of the performance evaluation to the Administrator at the appropriate address listed in § 63.13.
(i)
(1) Each owner or operator subject to the storage vessel provisions in § 63.646 shall keep the records specified in § 63.123 of subpart G except as specified in paragraphs (i)(1)(i) through (iv) of this section. Each owner or operator subject to the storage vessel provisions in § 63.660 shall keep records as specified in paragraphs (i)(1)(v) and (vi) of this section.
(ii) All references to § 63.122 in § 63.123 of subpart G shall be replaced with § 63.655(e).
(v) Each owner or operator of a Group 1 storage vessel subject to the provisions in § 63.660 shall keep records as specified in § 63.1065 or § 63.998, as applicable.
(vi) Each owner or operator of a Group 2 storage vessel shall keep the records specified in § 63.1065(a) of subpart WW. If a storage vessel is determined to be Group 2 because the weight percent total organic HAP of the stored liquid is less than or equal to 4 percent for existing sources or 2 percent for new sources, a record of any data, assumptions, and procedures used to make this determination shall be retained.
(4) For each closed vent system that contains bypass lines that could divert a vent stream away from the control device and either directly to the atmosphere or to a control device that does not comply with the requirements in § 63.643(a), the owner or operator shall keep a record of the information specified in either paragraph (i)(4)(i) or (ii) of this section, as applicable.
(i) The owner or operator shall maintain records of periods when flow was detected in the bypass line, including the date and time and the duration of the flow in the bypass line. For each flow event, the owner or operator shall maintain records sufficient to determine whether or not the detected flow included flow of a Group 1 miscellaneous process vent stream requiring control. For periods when the Group 1 miscellaneous process vent stream requiring control is diverted from the control device and released either directly to the atmosphere or to a control device that does not comply with the requirements in § 63.643(a), the owner or operator shall include an estimate of the volume of gas, the concentration of organic HAP in the gas and the resulting emissions of organic HAP that bypassed the control device using process knowledge and engineering estimates.
(ii) Where a seal mechanism is used to comply with § 63.644(c)(2), hourly records of flow are not required. In such cases, the owner or operator shall record the date that the monthly visual inspection of the seals or closure mechanisms is completed. The owner or operator shall also record the occurrence of all periods when the seal or closure mechanism is broken, the bypass line valve position has changed or the key for a lock-and-key type lock has been checked out. The owner or operator shall include an estimate of the volume of gas, the concentration of organic HAP in the gas and the resulting mass emissions of organic HAP from the Group 1 miscellaneous process vent stream requiring control that bypassed the control device or records sufficient to demonstrate that there was no flow of a Group 1 miscellaneous process vent stream requiring control during the period.
(5) The owner or operator of a heat exchange system subject to this subpart shall comply with the recordkeeping requirements in paragraphs (i)(5)(i) through (v) of this section and retain these records for 5 years.
(7) Each owner or operator subject to the delayed coking unit decoking operations provisions in § 63.657 must maintain records specified in paragraphs (i)(7)(i) through (iii) of this section.
(i) The average pressure or temperature, as applicable, for the 5-minute period prior to venting to the atmosphere, draining, or deheading the coke drum for each cooling cycle for each coke drum.
(ii) If complying with the 60-cycle rolling average, each 60-cycle rolling average pressure or temperature, as applicable, considering all coke drum venting events in the existing affected source.
(iii) For double-quench cooling cycles:
(A) The date, time and duration of each pre-vent draining event.
(B) The pressure or temperature of the coke drum vessel, as applicable, for the 15 minute period prior to the pre-vent draining.
(C) The drain water temperature at 1-minute intervals from the start of pre-vent draining to the complete closure of the drain valve.
(8) For fenceline monitoring systems subject to § 63.658, each owner or operator shall keep the records specified in paragraphs (i)(8)(i) through (x) of this section on an ongoing basis.
(i) Coordinates of all passive monitors, including replicate samplers and field blanks, and if applicable, the meteorological station. The owner or operator shall determine the coordinates using an instrument with an accuracy of at least 3 meters. The coordinates shall be in decimal degrees with at least five decimal places.
(ii) The start and stop times and dates for each sample, as well as the tube identifying information.
(iii) Sampling period average temperature and barometric pressure measurements.
(iv) For each outlier determined in accordance with Section 9.2 of Method 325A of appendix A of this part, the sampler location of and the concentration of the outlier and the evidence used to conclude that the result is an outlier.
(v) For samples that will be adjusted for a background, the location of and the concentration measured simultaneously by the background sampler, and the perimeter samplers to which it applies.
(vi) Individual sample results, the calculated Δc for benzene for each sampling period and the two samples used to determine it, whether background correction was used, and the annual average Δc calculated after each sampling period.
(vii) Method detection limit for each sample, including co-located samples and blanks.
(viii) Documentation of corrective action taken each time the action level was exceeded.
(ix) Other records as required by Methods 325A and 325B of appendix A of this part.
(x) If a near-field source correction is used as provided in § 63.658(i), records of hourly meteorological data, including temperature, barometric pressure, wind speed and wind direction, calculated daily unit vector wind direction and daily sigma theta, and other records specified in the site-specific monitoring plan.
(9) For each flare subject to § 63.670, each owner or operator shall keep the records specified in paragraphs (i)(9)(i) through (xii) of this section up-to-date and readily accessible, as applicable.
(i) Retain records of the output of the monitoring device used to detect the presence of a pilot flame as required in § 63.670(b) for a minimum of 2 years. Retain records of each 15-minute block during which there was at least one minute that no pilot flame is present when regulated material is routed to a flare for a minimum of 5 years.
(ii) Retain records of daily visible emissions observations or video surveillance images required in § 63.670(h) as specified in the paragraphs (i)(9)(ii)(A) through (C), as applicable, for a minimum of 3 years.
(A) If visible emissions observations are performed using Method 22 at 40 CFR part 60, appendix A-7, the record must identify whether the visible emissions observation was performed, the results of each observation, total duration of observed visible emissions, and whether it was a 5-minute or 2-hour observation. If the owner or operator performs visible emissions observations more than one time during a day, the record must also identify the date and time of day each visible emissions observation was performed.
(B) If video surveillance camera is used, the record must include all video surveillance images recorded, with time and date stamps.
(C) For each 2 hour period for which visible emissions are observed for more than 5 minutes in 2 consecutive hours, the record must include the date and time of the 2 hour period and an estimate of the cumulative number of minutes in the 2 hour period for which emissions were visible.
(iii) The 15-minute block average cumulative flows for flare vent gas and, if applicable, total steam, perimeter assist air, and premix assist air specified to be monitored under § 63.670(i), along with the date and time interval for the 15-minute block. If multiple monitoring locations are used to determine cumulative vent gas flow, total steam, perimeter assist air, and premix assist air, retain records of the 15-minute block average flows for each monitoring location for a minimum of 2 years, and retain the 15-minute block average cumulative flows that are used in subsequent calculations for a minimum of 5 years. If pressure and temperature monitoring is used, retain records of the 15-minute block average temperature, pressure and molecular weight of the flare vent gas or assist gas stream for each measurement location used to determine the 15-minute block average cumulative flows for a minimum of 2 years, and retain the 15-minute block average cumulative flows that are used in subsequent calculations for a minimum of 5 years.
(iv) The flare vent gas compositions specified to be monitored under § 63.670(j). Retain records of individual component concentrations from each compositional analyses for a minimum of 2 years. If NHVvg analyzer is used, retain records of the 15-minute block average values for a minimum of 5 years.
(v) Each 15-minute block average operating parameter calculated following the methods specified in § 63.670(k) through (n), as applicable.
(vi) [Reserved]
(vii) All periods during which operating values are outside of the applicable operating limits specified in § 63.670(d) through (f) when regulated material is being routed to the flare.
(viii) All periods during which the owner or operator does not perform flare monitoring according to the procedures in § 63.670(g) through (j).
(ix) Records of periods when there is flow of vent gas to the flare, but when there is no flow of regulated material to the flare, including the start and stop time and dates of periods of no regulated material flow.
(x) Records when the flow of vent gas exceeds the smokeless capacity of the flare, including start and stop time and dates of the flaring event.
(xi) Records of the root cause analysis and corrective action analysis conducted as required in § 63.670(o)(3), including an identification of the affected facility, the date and duration of the event, a statement noting whether the event resulted from the same root cause(s) identified in a previous analysis and either a description of the recommended corrective action(s) or an explanation of why corrective action is not necessary under § 63.670(o)(5)(i).
(xii) For any corrective action analysis for which implementation of corrective actions are required in § 63.670(o)(5), a description of the corrective action(s) completed within the first 45 days following the discharge and, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates.
(10) [Reserved]
(11) For each pressure relief device subject to the pressure release management work practice standards in § 63.648(j)(3), the owner or operator shall keep the records specified in paragraphs (i)(11)(i) through (iii) of this section.
(i) Records of the prevention measures implemented as required in § 63.648(j)(3)(ii), if applicable.
(ii) Records of the number of releases during each calendar year and the number of those releases for which the root cause was determined to be a force majeure event. Keep these records for the current calendar year and the past five calendar years.
(iii) For each release to the atmosphere, the owner or operator shall keep the records specified in paragraphs (i)(11)(iii)(A) through (D) of this section.
(A) The start and end time and date of each pressure release to the atmosphere.
(B) Records of any data, assumptions, and calculations used to estimate of the mass quantity of each organic HAP released during the event.
(C) Records of the root cause analysis and corrective action analysis conducted as required in § 63.648(j)(3)(iii), including an identification of the affected facility, the date and duration of the event, a statement noting whether the event resulted from the same root cause(s) identified in a previous analysis and either a description of the recommended corrective action(s) or an explanation of why corrective action is not necessary under § 63.648(j)(7)(i).
(D) For any corrective action analysis for which implementation of corrective actions are required in § 63.648(j)(7), a description of the corrective action(s) completed within the first 45 days following the discharge and, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates.
(12) For each maintenance vent opening subject to the requirements in § 63.643(c), the owner or operator shall keep the applicable records specified in (i)(12)(i) through (v) of this section.
(i) The owner or operator shall maintain standard site procedures used to deinventory equipment for safety purposes (
(ii) If complying with the requirements of § 63.643(c)(1)(i) and the lower explosive limit at the time of the vessel opening exceeds 10 percent, identification of the maintenance vent, the process units or equipment associated with the maintenance vent, the date of maintenance vent opening, and the lower explosive limit at the time of the vessel opening.
(iii) If complying with the requirements of § 63.643(c)(1)(ii) and either the vessel pressure at the time of the vessel opening exceeds 5 psig or the lower explosive limit at the time of the active purging was initiated exceeds 10 percent, identification of the maintenance vent, the process units or equipment associated with the maintenance vent, the date of maintenance vent opening, the pressure of the vessel or equipment at the time of discharge to the atmosphere and, if applicable, the lower explosive limit of the vapors in the equipment when active purging was initiated.
(iv) If complying with the requirements of § 63.643(c)(1)(iii), identification of the maintenance vent, the process units or equipment associated with the maintenance vent, the date of maintenance vent opening, and records used to estimate the total quantity of VOC in the equipment at the time the maintenance vent was opened to the atmosphere for each applicable maintenance vent opening.
(v) If complying with the requirements of § 63.643(c)(1)(iv), identification of the maintenance vent, the process units or equipment associated with the maintenance vent, records documenting the lack of a pure hydrogen supply, the date of maintenance vent opening, and the lower explosive limit of the vapors in the equipment at the time of discharge to the atmosphere for each applicable maintenance vent opening.
(c) * * *
(1) Approval of alternatives to the requirements in §§ 63.640, 63.642(g) through (l), 63.643, 63.646 through 63.652, 63.654, 63.657 through 63.660, and 63.670. Where these standards reference another subpart, the cited provisions will be delegated according to the delegation provisions of the referenced subpart. Where these standards reference another subpart and modify the requirements, the requirements shall be modified as described in this subpart. Delegation of the modified requirements will also occur according to the delegation provisions of the referenced subpart.
(a) Except as provided in paragraphs (e) and (f) of this section, each owner or operator of a delayed coking unit shall depressure each coke drum to a closed blowdown system until the coke drum vessel pressure or temperature measured at the top of the coke drum or in the overhead line of the coke drum as near as practical to the coke drum meets the applicable limits specified in paragraph (a)(1) or (2) of this section prior to venting to the atmosphere, draining or deheading the coke drum at the end of the cooling cycle.
(1) For delayed coking units at an existing affected source, meet either:
(i) An average vessel pressure of 2 psig determined on a rolling 60-event average; or
(ii) An average vessel temperature of 220 degrees Fahrenheit determined on a rolling 60-event average.
(2) For delayed coking units at a new affected source, meet either:
(i) A vessel pressure of 2.0 psig for each decoking event; or
(ii) A vessel temperature of 218 degrees Fahrenheit for each decoking event.
(b) Each owner or operator of a delayed coking unit complying with the pressure limits in paragraph (a)(1)(i) or (a)(2)(i) of this section shall install, operate, calibrate, and maintain a monitoring system, as specified in paragraphs (b)(1) through (5) of this section, to determine the coke drum vessel pressure.
(1) The pressure monitoring system must be in a representative location (at the top of the coke drum or in the overhead line as near as practical to the coke drum) that minimizes or eliminates pulsating pressure, vibration, and, to the extent practical, internal and external corrosion.
(2) The pressure monitoring system must be capable of measuring a pressure of 2.0 psig within ±0.5 psig.
(3) The pressure monitoring system must be verified annually or at the frequency recommended by the instrument manufacturer. The pressure monitoring system must be verified following any period of more than 24 hours throughout which the pressure exceeded the maximum rated pressure of the sensor, or the data recorder was off scale.
(4) All components of the pressure monitoring system must be visually inspected for integrity, oxidation and galvanic corrosion every 3 months, unless the system has a redundant pressure sensor.
(5) The output of the pressure monitoring system must be reviewed
(c) Each owner or operator of a delayed coking unit complying with the temperature limits in paragraph (a)(1)(ii) or (a)(2)(ii) of this section shall install, operate, calibrate, and maintain a continuous parameter monitoring system to measure the coke drum vessel temperature (at the top of the coke drum or in the overhead line as near as practical to the coke drum) according to the requirements specified in table 13 of this subpart.
(d) The owner or operator of a delayed coking unit shall determine the coke drum vessel pressure or temperature, as applicable, on a 5-minute rolling average basis while the coke drum is vented to the closed blowdown system and shall use the last complete 5-minute rolling average pressure or temperature just prior to initiating steps to isolate the coke drum prior to venting, draining or deheading to demonstrate compliance with the requirements in paragraph (a) of this section. Pressure or temperature readings after initiating steps to isolate the coke drum from the closed blowdown system just prior to atmospheric venting, draining, or deheading the coke drum shall not be used in determining the average coke drum vessel pressure or temperature for the purpose of compliance with the requirements in paragraph (a) of this section.
(e) The owner or operator of a delayed coking unit using the “water overflow” method of coke cooling must hardpipe the overflow water or otherwise prevent exposure of the overflow water to the atmosphere when transferring the overflow water to the overflow water storage tank whenever the coke drum vessel temperature exceeds 220 degrees Fahrenheit. The overflow water storage tank may be an open or fixed-roof tank provided that a submerged fill pipe (pipe outlet below existing liquid level in the tank) is used to transfer overflow water to the tank. The owner or operator of a delayed coking unit using the “water overflow” method of coke cooling shall determine the coke drum vessel temperature as specified in paragraphs (c) and (d) of this section regardless of the compliance method used to demonstrate compliance with the requirements in paragraph (a) of this section.
(f) The owner or operator of a delayed coking unit may partially drain a coke drum prior to achieving the applicable limits in paragraph (a) of this section in order to double-quench a coke drum that did not cool adequately using the normal cooling process steps provided that the owner or operator meets the conditions in paragraphs (f)(1) and (2) of this section.
(1) The owner or operator shall install, operate, calibrate, and maintain a continuous parameter monitoring system to measure the drain water temperature at the bottom of the coke drum or in the drain line as near as practical to the coke drum according to the requirements specified in table 13 of this subpart.
(2) The owner or operator must maintain the drain water temperature below 210 degrees Fahrenheit during the partial drain associated with the double-quench event.
(a) The owner or operator shall conduct sampling along the facility property boundary and analyze the samples in accordance with Methods 325A and 325B of appendix A of this part and paragraphs (b) through (k) of this section.
(b) The target analyte is benzene.
(c) The owner or operator shall determine passive monitor locations in accordance with Section 8.2 of Method 325A of appendix A of this part.
(1) As it pertains to this subpart, known sources of VOCs, as used in Section 8.2.1.3 in Method 325A of appendix A of this part for siting passive monitors means a wastewater treatment unit, process unit, or any emission source requiring control according to the requirements of this subpart, including marine vessel loading operations. For marine loading operations that are located offshore, one passive monitor should be sited on the shoreline adjacent to the dock.
(2) The owner or operator may collect one or more background samples if the owner or operator believes that an offsite upwind source or an onsite source excluded under § 63.640(g) may influence the sampler measurements. If the owner or operator elects to collect one or more background samples, the owner of operator must develop and submit a site-specific monitoring plan for approval according to the requirements in paragraph (i) of this section. Upon approval of the site-specific monitoring plan, the background sampler(s) should be operated co-currently with the routine samplers.
(3) The owner or operator shall collect at least one co-located duplicate sample for every 10 field samples per sampling period and at least two field blanks per sampling period, as described in Section 9.3 in Method 325A of appendix A of this part. The co-located duplicates may be collected at any one of the perimeter sampling locations.
(4) The owner or operator shall follow the procedure in Section 9.6 of Method 325B of appendix A of this part to determine the detection limit of benzene for each sampler used to collect samples, background samples (if the owner or operator elects to do so), co-located samples and blanks.
(d) The owner or operator shall collect and record meteorological data according to the applicable requirements in paragraphs (d)(1) through (3) of this section.
(1) If a near-field source correction is used as provided in paragraph (i)(1) of this section or if an alternative test method is used that provides time-resolved measurements, the owner or operator shall:
(i) Use an on-site meteorological station in accordance with Section 8.3 of Method 325A of appendix A of this part.
(ii) Collect and record hourly average meteorological data, including temperature, barometric pressure, wind speed and wind direction and calculate daily unit vector wind direction and daily sigma theta.
(2) For cases other than those specified in paragraph (d)(1) of this section, the owner or operator shall collect and record sampling period average temperature and barometric pressure using either an on-site meteorological station in accordance with Section 8.3 of Method 325A of appendix A of this part or, alternatively, using data from a United States Weather Service (USWS) meteorological station provided the USWS meteorological station is within 40 kilometers (25 miles) of the refinery.
(3) If an on-site meteorological station is used, the owner or operator shall follow the calibration and standardization procedures for meteorological measurements in EPA-454/B-08-002 (incorporated by reference—see § 63.14).
(e) The owner of operator shall use a sampling period and sampling frequency as specified in paragraphs (e)(1) through (3) of this section.
(1)
(2)
(3)
(i) If every sample at a monitoring site is at or below 0.9 μg/m
(ii) If every sample at a monitoring site that is monitored at the frequency specified in paragraph (e)(3)(i) of this section is at or below 0.9 μg/m
(iii) If every sample at a monitoring site that is monitored at the frequency specified in paragraph (e)(3)(ii) of this section is at or below 0.9 μg/m
(iv) If every sample at a monitoring site that is monitored at the frequency specified in paragraph (e)(3)(iii) of this section is at or below 0.9 μg/m
(v) If at any time a sample for a monitoring site that is monitored at the frequency specified in paragraphs (e)(3)(i) through (iv) of this section returns a result that is above 0.9 μg/m
(f) Within 45 days of completion of each sampling period, the owner or operator shall determine whether the results are above or below the action level as follows:
(1) The owner or operator shall determine the facility impact on the benzene concentration (Δc) for each 14-day sampling period according to either paragraph (f)(1)(i) or (ii) of this section, as applicable.
(i) Except when near-field source correction is used as provided in paragraph (i) of this section, the owner or operator shall determine the highest and lowest sample results for benzene concentrations from the sample pool and calculate Δc as the difference in these concentrations. The owner or operator shall adhere to the following procedures when one or more samples for the sampling period are below the method detection limit for benzene:
(A) If the lowest detected value of benzene is below detection, the owner or operator shall use zero as the lowest sample result when calculating Δc.
(B) If all sample results are below the method detection limit, the owner or operator shall use the method detection limit as the highest sample result.
(ii) When near-field source correction is used as provided in paragraph (i) of this section, the owner or operator shall determine Δc using the calculation protocols outlined in the approved site-specific monitoring plan and in paragraph (i) of this section.
(2) The owner or operator shall calculate the annual average Δc based on the average of the 26 most recent 14-day sampling periods. The owner or operator shall update this annual average value after receiving the results of each subsequent 14-day sampling period.
(3) The action level for benzene is 9 micrograms per cubic meter (μg/m3) on an annual average basis. If the annual average Δc value for benzene is less than or equal to 9 μg/m
(g) Within 5 days of determining that the action level has been exceeded for any annual average Δc and no longer than 50 days after completion of the sampling period, the owner or operator shall initiate a root cause analysis to determine the cause of such exceedance and to determine appropriate corrective action, such as those described in paragraphs (g)(1) through (4) of this section. The root cause analysis and initial corrective action analysis shall be completed and initial corrective actions taken no later than 45 days after determining there is an exceedance. Root cause analysis and corrective action may include, but is not limited to:
(1) Leak inspection using Method 21 of part 60, appendix A-7 of this chapter and repairing any leaks found.
(2) Leak inspection using optical gas imaging and repairing any leaks found.
(3) Visual inspection to determine the cause of the high benzene emissions and implementing repairs to reduce the level of emissions.
(4) Employing progressively more frequent sampling, analysis and meteorology (
(h) If, upon completion of the corrective action analysis and corrective actions such as those described in paragraph (g) of this section, the Δc value for the next 14-day sampling period for which the sampling start time begins after the completion of the corrective actions is greater than 9 μg/m
(i) An owner or operator may request approval from the Administrator for a site-specific monitoring plan to account for offsite upwind sources or onsite sources excluded under § 63.640(g) according to the requirements in paragraphs (i)(1) through (4) of this section.
(1) The owner or operator shall prepare and submit a site-specific monitoring plan and receive approval of the site-specific monitoring plan prior to using the near-field source alternative calculation for determining Δc provided in paragraph (i)(2) of this section. The site-specific monitoring plan shall include, at a minimum, the elements specified in paragraphs (i)(1)(i) through (v) of this section. The procedures in Section 12 of Method 325A of appendix A of this part are not required, but may be used, if applicable, when determining near-field source contributions.
(i) Identification of the near-field source or sources. For onsite sources, documentation that the onsite source is excluded under § 63.640(g) and identification of the specific provision in § 63.640(g) that applies to the source.
(ii) Location of the additional monitoring stations that shall be used to determine the uniform background concentration and the near-field source concentration contribution.
(iii) Identification of the fenceline monitoring locations impacted by the near-field source. If more than one near-field source is present, identify the near-field source or sources that are expected to contribute to the concentration at that monitoring location.
(iv) A description of (including sample calculations illustrating) the planned data reduction and calculations to determine the near-field source concentration contribution for each monitoring location.
(v) If more frequent monitoring or a monitoring station other than a passive diffusive tube monitoring station is proposed, provide a detailed description of the measurement methods, measurement frequency, and recording frequency for determining the uniform background or near-field source concentration contribution.
(2) When an approved site-specific monitoring plan is used, the owner or operator shall determine Δc for comparison with the 9 μg/m
(i) For each monitoring location, calculate Δc
(ii) When one or more samples for the sampling period are below the method detection limit for benzene, adhere to the following procedures:
(A) If the benzene concentration at the monitoring location used for the uniform background concentration is below the method detection limit, the owner or operator shall use zero for UB for that monitoring period.
(B) If the benzene concentration at the monitoring location(s) used to determine the near-field source contributing concentration is below the method detection limit, the owner or operator shall use zero for the monitoring location concentration when calculating NFS
(C) If a fenceline monitoring location sample result is below the method detection limit, the owner or operator shall use the method detection limit as the sample result.
(iii) Determine Δc for the monitoring period as the maximum value of Δc
(3) The site-specific monitoring plan shall be submitted and approved as described in paragraphs (i)(3)(i) through (iv) of this section.
(i) The site-specific monitoring plan must be submitted to the Administrator for approval.
(ii) The site-specific monitoring plan shall also be submitted to the following address: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (E143-01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be submitted to
(iii) The Administrator shall approve or disapprove the plan in 90 days. The plan shall be considered approved if the Administrator either approves the plan in writing, or fails to disapprove the plan in writing. The 90-day period shall begin when the Administrator receives the plan.
(iv) If the Administrator finds any deficiencies in the site-specific monitoring plan and disapproves the plan in writing, the owner or operator may revise and resubmit the site-specific monitoring plan following the requirements in paragraphs (i)(3)(i) and (ii) of this section. The 90-day period starts over with the resubmission of the revised monitoring plan.
(4) The approval by the Administrator of a site-specific monitoring plan will be based on the completeness, accuracy and reasonableness of the request for a site-specific monitoring plan. Factors that the Administrator will consider in reviewing the request for a site-specific monitoring plan include, but are not limited to, those described in paragraphs (i)(4)(i) through (v) of this section.
(i) The identification of the near-field source or sources. For onsite sources, the documentation provided that the onsite source is excluded under § 63.640(g).
(ii) The monitoring location selected to determine the uniform background concentration or an indication that no uniform background concentration monitor will be used.
(iii) The location(s) selected for additional monitoring to determine the near-field source concentration contribution.
(iv) The identification of the fenceline monitoring locations impacted by the near-field source or sources.
(v) The appropriateness of the planned data reduction and calculations to determine the near-field source concentration contribution for each monitoring location.
(vi) If more frequent monitoring is proposed, the adequacy of the description of the measurement and
(j) The owner or operator shall comply with the applicable recordkeeping and reporting requirements in § 63.655(h) and (i).
(k) As outlined in § 63.7(f), the owner or operator may submit a request for an alternative test method. At a minimum, the request must follow the requirements outlined in paragraphs (k)(1) through (7) of this section.
(1) The alternative method may be used in lieu of all or a partial number of passive samplers required in Method 325A of appendix A of this part.
(2) The alternative method must be validated according to Method 301 in appendix A of this part or contain performance based procedures and indicators to ensure self-validation.
(3) The method detection limit must nominally be at least an order of magnitude below the action level,
(4) The spatial coverage must be equal to or better than the spatial coverage provided in Method 325A of appendix A of this part.
(i) For path average concentration open-path instruments, the physical path length of the measurement shall be no more than a passive sample footprint (the spacing that would be provided by the sorbent traps when following Method 325A). For example, if Method 325A requires spacing monitors A and B 610 meters (2000 feet) apart, then the physical path length limit for the measurement at that portion of the fenceline shall be no more than 610 meters (2000 feet).
(ii) For range resolved open-path instrument or approach, the instrument or approach must be able to resolve an average concentration over each passive sampler footprint within the path length of the instrument.
(iii) The extra samplers required in Sections 8.2.1.3 of Method 325A may be omitted when they fall within the path length of an open-path instrument.
(5) At a minimum, non-integrating alternative test methods must provide a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period.
(6) For alternative test methods capable of real time measurements (less than a 5 minute sampling and analysis cycle), the alternative test method may allow for elimination of data points corresponding to outside emission sources for purpose of calculation of the high point for the two week average. The alternative test method approach must have wind speed, direction and stability class of the same time resolution and within the footprint of the instrument.
(7) For purposes of averaging data points to determine the Δc for the 14-day average high sample result, all results measured under the method detection limit must use the method detection limit. For purposes of averaging data points for the 14-day average low sample result, all results measured under the method detection limit must use zero.
On and after the applicable compliance date for a Group 1 storage vessel located at a new or existing source as specified in § 63.640(h), the owner or operator of a Group 1 storage vessel that is part of a new or existing source shall comply with the requirements in subpart WW or SS of this part according to the requirements in paragraphs (a) through (i) of this section.
(a) As used in this section, all terms not defined in § 63.641 shall have the meaning given them in subpart A, WW, or SS of this part. The definitions of “Group 1 storage vessel” (paragraph (2)) and “Storage vessel” in § 63.641 shall apply in lieu of the definition of “Storage vessel” in § 63.1061.
(1) An owner or operator may use good engineering judgment or test results to determine the stored liquid weight percent total organic HAP for purposes of group determination. Data, assumptions, and procedures used in the determination shall be documented.
(2) When an owner or operator and the Administrator do not agree on whether the annual average weight percent organic HAP in the stored liquid is above or below 4 percent for a storage vessel at an existing source or above or below 2 percent for a storage vessel at a new source, an appropriate method (based on the type of liquid stored) as published by EPA or a consensus-based standards organization shall be used. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373,
(b) A floating roof storage vessel complying with the requirements of subpart WW of this part may comply with the control option specified in paragraph (b)(1) of this section and, if equipped with a ladder having at least one slotted leg, shall comply with one of the control options as described in paragraph (b)(2) of this section.
(1) In addition to the options presented in §§ 63.1063(a)(2)(viii)(A) and (B) and 63.1064, a floating roof storage vessel may comply with § 63.1063(a)(2)(vii) using a flexible enclosure device and either a gasketed or welded cap on the top of the guidepole.
(2) Each opening through a floating roof for a ladder having at least one slotted leg shall be equipped with one of the configurations specified in paragraphs (b)(2)(i) through (iii) of this section.
(i) A pole float in the slotted leg and pole wipers for both legs. The wiper or seal of the pole float must be at or above the height of the pole wiper.
(ii) A ladder sleeve and pole wipers for both legs of the ladder.
(iii) A flexible enclosure device and either a gasketed or welded cap on the top of the slotted leg.
(c) For the purposes of this subpart, references shall apply as specified in paragraphs (c)(1) through (6) of this section.
(1) All references to “the proposal date for a referencing subpart” and “the proposal date of the referencing subpart” in subpart WW of this part mean June 30, 2014.
(2) All references to “promulgation of the referencing subpart” and “the promulgation date of the referencing subpart” in subpart WW of this part mean February 1, 2016.
(3) All references to “promulgation date of standards for an affected source or affected facility under a referencing subpart” in subpart SS of this part mean February 1, 2016.
(4) All references to “the proposal date of the relevant standard established pursuant to CAA section 112(f)” in
(5) All references to “the proposal date of a relevant standard established pursuant to CAA section 112(d)” in subpart SS of this part mean July 14, 1994.
(6) All references to the “required control efficiency” in subpart SS of this part mean reduction of organic HAP emissions by 95 percent or to an outlet concentration of 20 ppmv.
(d) For an uncontrolled fixed roof storage vessel that commenced construction on or before June 30, 2014, and that meets the definition of “Group 1 storage vessel”, paragraph (2), in § 63.641 but not the definition of “Group 1 storage vessel”, paragraph (1), in § 63.641, the requirements of § 63.982 and/or § 63.1062 do not apply until the next time the storage vessel is completely emptied and degassed, or January 30, 2026, whichever occurs first.
(e) Failure to perform inspections and monitoring required by this section shall constitute a violation of the applicable standard of this subpart.
(f) References in § 63.1066(a) to initial startup notification requirements do not apply.
(g) References to the Notification of Compliance Status in § 63.999(b) mean the Notification of Compliance Status required by § 63.655(f).
(h) References to the Periodic Reports in §§ 63.1066(b) and 63.999(c) mean the Periodic Report required by § 63.655(g).
(i) Owners or operators electing to comply with the requirements in subpart SS of this part for a Group 1 storage vessel must comply with the requirements in paragraphs (i)(1) through (3) of this section.
(1) If a flare is used as a control device, the flare shall meet the requirements of § 63.670 instead of the flare requirements in § 63.987.
(2) If a closed vent system contains a bypass line, the owner or operator shall comply with the provisions of either § 63.983(a)(3)(i) or (ii) for each closed vent system that contains bypass lines that could divert a vent stream either directly to the atmosphere or to a control device that does not comply with the requirements in subpart SS of this part. Except as provided in paragraphs (i)(2)(i) and (ii) of this section, use of the bypass at any time to divert a Group 1 storage vessel to either directly to the atmosphere or to a control device that does not comply with the requirements in subpart SS of this part is an emissions standards violation. Equipment such as low leg drains and equipment subject to § 63.648 are not subject to this paragraph (i)(2).
(i) If planned routine maintenance of the control device cannot be performed during periods that storage vessel emissions are vented to the control device or when the storage vessel is taken out of service for inspections or other planned maintenance reasons, the owner or operator may bypass the control device.
(ii) Periods for which storage vessel control device may be bypassed for planned routine maintenance of the control device shall not exceed 240 hours per calendar year.
(3) If storage vessel emissions are routed to a fuel gas system or process, the fuel gas system or process shall be operating at all times when regulated emissions are routed to it. The exception in § 63.984(a)(1) does not apply.
On or before January 30, 2019, the owner or operator of a flare used as a control device for an emission point subject to this subpart shall meet the applicable requirements for flares as specified in paragraphs (a) through (q) of this section and the applicable requirements in § 63.671. The owner or operator may elect to comply with the requirements of paragraph (r) of this section in lieu of the requirements in paragraphs (d) through (f) of this section, as applicable.
(b)
(c)
(d)
(1) Except as provided in paragraph (d)(2) of this section, the actual flare tip velocity (V
(2) V
(e)
(f)
(g)
(h)
(1) At least once per day, conduct visible emissions observations using an observation period of 5 minutes using Method 22 at 40 CFR part 60, appendix A-7. If at any time the owner or operator sees visible emissions, even if the minimum required daily visible emission monitoring has already been performed, the owner or operator shall immediately begin an observation period of 5 minutes using Method 22 at 40 CFR part 60, appendix A-7. If visible emissions are observed for more than one continuous minute during any 5-minute observation period, the observation period using Method 22 at 40 CFR part 60, appendix A-7 must be extended to 2 hours or until 5-minutes of visible emissions are observed.
(2) Use a video surveillance camera to continuously record (at least one frame every 15 seconds with time and date stamps) images of the flare flame and a reasonable distance above the flare flame at an angle suitable for visual emissions observations. The owner or operator must provide real-time video surveillance camera output to the control room or other continuously manned location where the camera images may be viewed at any time.
(i)
(1) The flow rate monitoring systems must be able to correct for the temperature and pressure of the system and output parameters in standard conditions (
(2) Mass flow monitors may be used for determining volumetric flow rate of flare vent gas provided the molecular weight of the flare vent gas is determined using compositional analysis as specified in paragraph (j) of this section so that the mass flow rate can be converted to volumetric flow at standard conditions using the following equation.
(3) Mass flow monitors may be used for determining volumetric flow rate of assist air or assist steam. Use equation in paragraph (i)(2) of this section to convert mass flow rates to volumetric flow rates. Use a molecular weight of 18 pounds per pound-mole for assist steam and use a molecular weight of 29 pounds per pound-mole for assist air.
(4) Continuous pressure/temperature monitoring system(s) and appropriate engineering calculations may be used in lieu of a continuous volumetric flow monitoring systems provided the molecular weight of the gas is known. For assist steam, use a molecular weight of 18 pounds per pound-mole. For assist air, use a molecular weight of 29 pounds per pound-mole. For flare vent gas, molecular weight must be determined using compositional analysis as specified in paragraph (j) of this section.
(j)
(1) Except as provided in paragraphs (j)(5) and (6) of this section, the owner or operator shall install, operate, calibrate, and maintain a monitoring system capable of continuously measuring (
(2) Except as provided in paragraphs (j)(5) and (6) of this section, the owner or operator shall install, operate, and maintain a grab sampling system capable of collecting an evacuated canister sample for subsequent compositional analysis at least once every eight hours while there is flow of regulated material to the flare. Subsequent compositional analysis of the samples must be performed according to Method 18 of 40 CFR part 60, appendix A-6, ASTM D6420-99 (Reapproved 2010), ASTM D1945-03 (Reapproved 2010), ASTM D1945-14 or ASTM UOP539-12 (all incorporated by reference—see § 63.14).
(3) Except as provided in paragraphs (j)(5) and (6) of this section, the owner or operator shall install, operate, calibrate, and maintain a calorimeter capable of continuously measuring, calculating, and recording NHV
(4) If the owner or operator uses a continuous net heating value monitor according to paragraph (j)(3) of this section, the owner or operator may, at their discretion, install, operate, calibrate, and maintain a monitoring
(5) Direct compositional or net heating value monitoring is not required for purchased (“pipeline quality”) natural gas streams. The net heating value of purchased natural gas streams may be determined using annual or more frequent grab sampling at any one representative location. Alternatively, the net heating value of any purchased natural gas stream can be assumed to be 920 Btu/scf.
(6) Direct compositional or net heating value monitoring is not required for gas streams that have been demonstrated to have consistent composition (or a fixed minimum net heating value) according to the methods in paragraphs (j)(6)(i) through (v) of this section.
(i) The owner or operator shall submit to the Administrator a written application for an exemption from monitoring. The application must contain the following information:
(A) A description of the flare gas stream/system to be considered, including submission of a portion of the appropriate piping diagrams indicating the boundaries of the flare gas stream/system and the affected flare(s) to be considered;
(B) A statement that there are no crossover or entry points to be introduced into the flare gas stream/system (this should be shown in the piping diagrams) prior to the point where the flow rate of the gas streams is measured;
(C) An explanation of the conditions that ensure that the flare gas net heating value is consistent and, if flare gas net heating value is expected to vary (
(D) The supporting test results from sampling the requested flare gas stream/system for the net heating value. Sampling data must include, at minimum, 2 weeks of daily measurement values (14 grab samples) for frequently operated flare gas streams/systems; for infrequently operated flare gas streams/systems, seven grab samples must be collected unless other additional information would support reduced sampling. If the flare gas stream composition can vary, samples must be taken during those conditions expected to result in lowest net heating value identified in paragraph (j)(6)(i)(C) of this section. The owner or operator shall determine net heating value for the gas stream using either gas composition analysis or net heating value monitor (with optional hydrogen concentration analyzer) according to the method provided in paragraph (l) of this section; and
(E) A description of how the 2 weeks (or seven samples for infrequently operated flare gas streams/systems) of monitoring results compares to the typical range of net heating values expected for the flare gas stream/system going to the affected flare (
(F) The net heating value to be used for all flows of the flare vent gas from the flare gas stream/system covered in the application. A single net heating value must be assigned to the flare vent gas either by selecting the lowest net heating value measured in the sampling program or by determining the 95th percent confidence interval on the mean value of all samples collected using the t-distribution statistic (which is 1.943 for 7 grab samples or 1.771 for 14 grab samples).
(ii) The effective date of the exemption is the date of submission of the information required in paragraph (j)(6)(i) of this section.
(iii) No further action is required unless refinery operating conditions change in such a way that affects the exempt fuel gas stream/system (
(A) If the operation change results in a flare vent gas net heating value that is still within the range of net heating values included in the original application, the owner or operator shall determine the net heating value on a grab sample and record the results as proof that the net heating value assigned to the vent gas stream in the original application is still appropriate.
(B) If the operation change results in a flare vent gas net heating value that is lower than the net heating value assigned to the vent gas stream in the original application, the owner or operator may submit new information following the procedures of paragraph (j)(6)(i) of this section within 60 days (or within 30 days after the seventh grab sample is tested for infrequently operated process units).
(C) If the operation change results in a flare vent gas net heating value has greater variability in the flare gas stream/system such the owner or operator chooses not to submit new information to support an exemption, the owner or operator must begin monitoring the composition or net heat content of the flare vent gas stream using the methods in this section (
(k)
(1) The owner or operator shall use design and engineering principles to determine the unobstructed cross sectional area of the flare tip. The unobstructed cross sectional area of the flare tip is the total tip area that vent gas can pass through. This area does not include any stability tabs, stability rings, and upper steam or air tubes because flare vent gas does not exit through them.
(2) The owner or operator shall determine the cumulative volumetric flow of flare vent gas for each 15-minute block average period using the data from the continuous flow monitoring system required in paragraph (i) of this section according to the following requirements, as applicable. If desired, the cumulative flow rate for a 15-minute block period only needs to include flow during those periods when regulated material is sent to the flare, but owners or operators may elect to calculate the cumulative flow rates across the entire 15-minute block period for any 15-minute block period where there is regulated material flow to the flare.
(i) Use set 15-minute time periods starting at 12 midnight to 12:15 a.m., 12:15 a.m. to 12:30 a.m. and so on concluding at 11:45 p.m. to midnight when calculating 15-minute block average flow volumes.
(ii) If continuous pressure/temperature monitoring system(s) and engineering calculations are used as allowed under paragraph (i)(4) of this section, the owner or operator shall, at a minimum, determine the 15-minute block average temperature and pressure from the monitoring system and use those values to perform the engineering calculations to determine the cumulative flow over the 15-minute block average period. Alternatively, the owner or operator may divide the 15-minute block average period into equal duration subperiods (
(3) The 15-minute block average V
(4) If the owner or operator chooses to comply with paragraph (d)(2) of this section, the owner or operator shall also determine the net heating value of the flare vent gas following the requirements in paragraphs (j) and (l) of this section and calculate V
(l)
(1) If compositional analysis data are collected as provided in paragraph (j)(1) or (2) of this section, the owner or operator shall determine NHV
(2) If direct net heating value monitoring data are collected as provided in paragraph (j)(3) of this section but a hydrogen concentration monitor is not used, the owner or operator shall use the direct output of the monitoring system(s) (in Btu/scf) to determine the NHV
(3) If direct net heating value monitoring data are collected as provided in paragraph (j)(3) of this section and hydrogen concentration monitoring data are collected as provided in paragraph (j)(4) of this section, the owner or operator shall use the following equation to determine NHV
(4) Use set 15-minute time periods starting at 12 midnight to 12:15 a.m., 12:15 a.m. to 12:30 a.m. and so on concluding at 11:45 p.m. to midnight when calculating 15-minute block averages.
(5) When a continuous monitoring system is used as provided in paragraph (j)(1) or (3) of this section and, if applicable, paragraph (j)(4) of this section, the owner or operator may elect to determine the 15-minute block average NHV
(i)
(A) Use the results from the first sample collected during an event, (for periodic flare vent gas flow events) for the first 15-minute block associated with that event.
(B) If the results from the first sample collected during an event (for periodic flare vent gas flow events) are not available until after the second 15-minute block starts, use the results from the first sample collected during an event for the second 15-minute block associated with that event.
(C) For all other cases, use the results that are available from the most recent sample prior to the 15-minute block period for that 15-minute block period for all flare vent gas steams. For the purpose of this requirement, use the time that the results become available rather than the time the sample was collected. For example, if a sample is collected at 12:25 a.m. and the analysis is completed at 12:38 a.m., the results are available at 12:38 a.m. and these results would be used to determine compliance during the 15-minute block period from 12:45 a.m. to 1:00 a.m.
(ii)
(A) If the results from the first sample collected during an event (for periodic flare vent gas flow events) are not available until after the second 15-minute block starts, use the results from the first sample collected during an event for the first 15-minute block associated with that event.
(B) For all other cases, use the arithmetic average of all NHV
(6) When grab samples are used to determine flare vent gas composition:
(i) Use the analytical results from the first grab sample collected for an event for all 15-minute periods from the start of the event through the 15-minute block prior to the 15-minute block in which a subsequent grab sample is collected.
(ii) Use the results from subsequent grab sampling events for all 15 minute periods starting with the 15-minute block in which the sample was collected and ending with the 15-minute block prior to the 15-minute block in which the next grab sample is collected. For
(7) If the owner or operator monitors separate gas streams that combine to comprise the total flare vent gas flow, the 15-minute block average net heating value shall be determined separately for each measurement location according to the methods in paragraphs (l)(1) through (6) of this section and a flow-weighted average of the gas stream net heating values shall be used to determine the 15-minute block average net heating value of the cumulative flare vent gas.
(m)
(1) Except as specified in paragraph (m)(2) of this section, determine the 15-minute block average NHV
(2) Owners or operators of flares that use the feed-forward calculation methodology in paragraph (l)(5)(i) of this section and that monitor gas composition or net heating value in a location representative of the cumulative vent gas stream and that directly monitor supplemental natural gas flow additions to the flare must determine the 15-minute block average NHV
(n)
(1) Except as specified in paragraph (n)(2) of this section, determine the 15-minute block average NHV
(2) Owners or operators of flares that use the feed-forward calculation methodology in paragraph (l)(5)(i) of this section and that monitor gas composition or net heating value in a location representative of the cumulative vent gas stream and that directly monitor supplemental natural gas flow additions to the flare must determine the 15-minute block average NHV
(o)
(1) Develop a flare management plan to minimize flaring during periods of startup, shutdown, or emergency releases. The flare management plan must include the information described in paragraphs (o)(1)(i) through (vii) of this section.
(i) A listing of all refinery process units, ancillary equipment, and fuel gas systems connected to the flare for each affected flare.
(ii) An assessment of whether discharges to affected flares from these process units, ancillary equipment and fuel gas systems can be minimized or prevented during periods of startup, shutdown, or emergency releases. The flare minimization assessment must (at a minimum) consider the items in paragraphs (o)(1)(ii)(A) through (C) of this section. The assessment must provide clear rationale in terms of costs (capital and annual operating), natural gas offset credits (if applicable), technical feasibility, secondary environmental impacts and safety considerations for the selected minimization alternative(s) or a statement, with justifications, that flow reduction could not be achieved. Based upon the assessment, each owner or operator of an affected flare shall identify the minimization alternatives that it has implemented by the due date of the flare management plan and shall include a schedule for the prompt implementation of any selected measures that cannot reasonably be completed as of that date.
(A) Modification in startup and shutdown procedures to reduce the quantity of process gas discharge to the flare.
(B) Implementation of prevention measures listed for pressure relief devices in § 63.648(j)(5) for each pressure relief valve that can discharge to the flare.
(C) Installation of a flare gas recovery system or, for facilities that are fuel gas rich, a flare gas recovery system and a co-generation unit or combined heat and power unit.
(iii) A description of each affected flare containing the information in paragraphs (o)(1)(iii)(A) through (G) of this section.
(A) A general description of the flare, including whether it is a ground flare or elevated (including height), the type of assist system (
(B) The smokeless capacity of the flare based on design conditions. Note: A single value must be provided for the smokeless capacity of the flare.
(C) The maximum vent gas flow rate (hydraulic load capacity).
(D) The maximum supplemental gas flow rate.
(E) For flares that receive assist steam, the minimum total steam rate and the maximum total steam rate.
(F) For flares that receive assist air, an indication of whether the fan/blower is single speed, multi-fixed speed (
(G) Simple process flow diagram showing the locations of the flare following components of the flare: Flare tip (date installed, manufacturer, nominal and effective tip diameter, tip drawing); knockout or surge drum(s) or pot(s) (including dimensions and design capacities); flare header(s) and subheader(s); assist system; and ignition system.
(iv) Description and simple process flow diagram showing all gas lines (including flare waste gas, purge or sweep gas (as applicable), supplemental gas) that are associated with the flare. For purge, sweep, supplemental gas, identify the type of gas used. Designate which lines are exempt from composition or net heating value monitoring and why (
(v) For each flow rate, gas composition, net heating value or hydrogen concentration monitor identified in paragraph (o)(1)(iv) of this section, provide a detailed description of the manufacturer's specifications, including, but not limited to, make, model, type, range, precision, accuracy, calibration, maintenance and quality assurance procedures.
(vi) For each pressure relief valve vented to the flare identified in paragraph (o)(1)(iv) of this section, provide a detailed description of each pressure release valve, including type of relief device (rupture disc, valve type) diameter of the relief valve, set pressure of the relief valve and listing of the prevention measures implemented. This
(vii) Procedures to minimize or eliminate discharges to the flare during the planned startup and shutdown of the refinery process units and ancillary equipment that are connected to the affected flare, together with a schedule for the prompt implementation of any procedures that cannot reasonably be implemented as of the date of the submission of the flare management plan.
(2) Each owner or operator required to develop and implement a written flare management plan as described in paragraph (o)(1) of this section must submit the plan to the Administrator as described in paragraphs (o)(2)(i) through (iii) of this section.
(i) The owner or operator must develop and implement the flare management plan no later than January 30, 2019 or at startup for a new flare that commenced construction on or after February 1, 2016.
(ii) The owner or operator must comply with the plan as submitted by the date specified in paragraph (o)(2)(i) of this section. The plan should be updated periodically to account for changes in the operation of the flare, such as new connections to the flare or the installation of a flare gas recovery system, but the plan need be re-submitted to the Administrator only if the owner or operator alters the design smokeless capacity of the flare. The owner or operator must comply with the updated plan as submitted.
(iii) All versions of the plan submitted to the Administrator shall also be submitted to the following address: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (E143-01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be submitted to
(3) The owner or operator of a flare subject to this subpart shall conduct a root cause analysis and a corrective action analysis for each flow event that contains regulated material and that meets either the criteria in paragraph (o)(3)(i) or (ii) of this section.
(i) The vent gas flow rate exceeds the smokeless capacity of the flare and visible emissions are present from the flare for more than 5 minutes during any 2 consecutive hours during the release event.
(ii) The vent gas flow rate exceeds the smokeless capacity of the flare and the 15-minute block average flare tip velocity exceeds the maximum flare tip velocity determined using the methods in paragraph (d)(2) of this section.
(4) A root cause analysis and corrective action analysis must be completed as soon as possible, but no later than 45 days after a flare flow event meeting the criteria in paragraph (o)(3)(i) or (ii) of this section. Special circumstances affecting the number of root cause analyses and/or corrective action analyses are provided in paragraphs (o)(4)(i) through (v) of this section.
(i) You may conduct a single root cause analysis and corrective action analysis for a single continuous flare flow event that meets both of the criteria in paragraphs (o)(3)(i) and (ii) of this section.
(ii) You may conduct a single root cause analysis and corrective action analysis for a single continuous flare flow event regardless of the number of 15-minute block periods in which the flare tip velocity was exceeded or the number of 2 hour periods that contain more the 5 minutes of visible emissions.
(iii) You may conduct a single root cause analysis and corrective action analysis for a single event that causes two or more flares that are operated in series (
(iv) You may conduct a single root cause analysis and corrective action analysis for a single event that causes two or more flares to have a flow event meeting the criteria in paragraph (o)(3)(i) or (ii) of this section, regardless of the configuration of the flares, if the root cause is reasonably expected to be a force majeure event, as defined in this subpart.
(v) Except as provided in paragraphs (o)(4)(iii) and (iv) of this section, if more than one flare has a flow event that meets the criteria in paragraph (o)(3)(i) or (ii) of this section during the same time period, an initial root cause analysis shall be conducted separately for each flare that has a flow event meeting the criteria in paragraph (o)(3)(i) or (ii) of this section. If the initial root cause analysis indicates that the flow events have the same root cause(s), the initially separate root cause analyses may be recorded as a single root cause analysis and a single corrective action analysis may be conducted.
(5) Each owner or operator of a flare required to conduct a root cause analysis and corrective action analysis as specified in paragraphs (o)(3) and (4) of this section shall implement the corrective action(s) identified in the corrective action analysis in accordance with the applicable requirements in paragraphs (o)(5)(i) through (iii) of this section.
(i) All corrective action(s) must be implemented within 45 days of the event for which the root cause and corrective action analyses were required or as soon thereafter as practicable. If an owner or operator concludes that no corrective action should be implemented, the owner or operator shall record and explain the basis for that conclusion no later than 45 days following the event.
(ii) For corrective actions that cannot be fully implemented within 45 days following the event for which the root cause and corrective action analyses were required, the owner or operator shall develop an implementation schedule to complete the corrective action(s) as soon as practicable.
(iii) No later than 45 days following the event for which a root cause and corrective action analyses were required, the owner or operator shall record the corrective action(s) completed to date, and, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates.
(6) The owner or operator shall determine the total number of events for which a root cause and corrective action analyses was required during the calendar year for each affected flare separately for events meeting the criteria in paragraph (o)(3)(i) of this section and those meeting the criteria in paragraph (o)(3)(ii) of this section. For the purpose of this requirement, a single root cause analysis conducted for an event that met both of the criteria in paragraphs (o)(3)(i) and (ii) of this section would be counted as an event under each of the separate criteria counts for that flare. Additionally, if a single root cause analysis was conducted for an event that caused multiple flares to meet the criteria in paragraph (o)(3)(i) or (ii) of this section, that event would count as an event for each of the flares for each criteria in paragraph (o)(3) of this section that was met during that event. The owner or operator shall also determine the total number of events for which a root cause and correct action analyses was required and the analyses concluded that the root cause was a force majeure event, as defined in this subpart.
(7) The following events would be a violation of this emergency flaring work practice standard.
(i) Any flow event for which a root cause analysis was required and the root
(ii) Two visible emissions exceedance events meeting the criteria in paragraph (o)(3)(i) of this section that were not caused by a force majeure event from a single flare in a 3 calendar year period for the same root cause for the same equipment.
(iii) Two flare tip velocity exceedance events meeting the criteria in paragraph (o)(3)(ii) of this section that were not caused by a force majeure event from a single flare in a 3 calendar year period for the same root cause for the same equipment.
(iv) Three visible emissions exceedance events meeting the criteria in paragraph (o)(3)(i) of this section that were not caused by a force majeure event from a single flare in a 3 calendar year period for any reason.
(v) Three flare tip velocity exceedance events meeting the criteria in paragraph (o)(3)(ii) of this section that were not caused by a force majeure event from a single flare in a 3 calendar year period for any reason.
(p)
(q)
(r)
(1) The owner or operator shall prepare and submit a site-specific test plan and receive approval of the site-specific performance evaluation plan prior to conducting any flare performance evaluation test runs intended for use in developing site-specific operating limits. The site-specific performance evaluation plan shall include, at a minimum, the elements specified in paragraphs (r)(1)(i) through (ix) of this section. Upon approval of the site-specific performance evaluation plan, the owner or operator shall conduct performance evaluation test runs for the flare following the procedures described in the site-specific performance evaluation plan.
(i) The design and dimensions of the flare, flare type (air-assisted only, steam-assisted only, air- and steam-assisted, pressure-assisted, or non-assisted), and description of gas being flared, including quantity of gas flared, frequency of flaring events (if periodic), expected net heating value of flare vent gas, minimum total steam assist rate.
(ii) The operating conditions (vent gas compositions, vent gas flow rates and assist flow rates, if applicable) likely to be encountered by the flare during normal operations and the operating conditions for the test period.
(iii) A description of (including sample calculations illustrating) the planned data reduction and calculations to determine the flare combustion or destruction efficiency.
(iv) Site-specific operating parameters to be monitored continuously during the flare performance evaluation. These parameters may include but are not limited to vent gas flow rate, steam and/or air assist flow rates, and flare vent gas composition. If new operating parameters are proposed for use other than those specified in paragraphs (d) through (f) of this section, an explanation of the relevance of the proposed operating parameter(s) as an indicator of flare combustion performance and why the alternative operating parameter(s) can adequately ensure that the flare achieves the required combustion efficiency.
(v) A detailed description of the measurement methods, monitored pollutant(s), measurement locations, measurement frequency, and recording frequency proposed for both emission measurements and flare operating parameters.
(vi) A description of (including sample calculations illustrating) the planned data reduction and calculations to determine the flare operating parameters.
(vii) The minimum number and length of test runs and range of operating values to be evaluated during the performance evaluation. A sufficient number of test runs shall be conducted to identify the point at which the combustion/destruction efficiency of the flare deteriorates.
(viii) [Reserved]
(ix) Test schedule.
(2) The request for flare-specific operating limits shall include sufficient and appropriate data, as determined by the Administrator, to allow the Administrator to confirm that the selected site-specific operating limit(s) adequately ensures that the flare destruction efficiency is 98 percent or greater or that the flare combustion efficiency is 96.5 percent or greater at all times. At a minimum, the request shall contain the information described in paragraphs (r)(2)(i) through (iv) of this section.
(i) The design and dimensions of the flare, flare type (air-assisted only, steam-assisted only, air- and steam-assisted, pressure-assisted, or non-assisted), and description of gas being flared, including quantity of gas flared, frequency of flaring events (if periodic), expected net heating value of flare vent gas, minimum total steam assist rate.
(ii) Results of each performance evaluation test run conducted, including, at a minimum:
(A) The measured combustion/destruction efficiency.
(B) The measured or calculated operating parameters for each test run. If operating parameters are calculated, the raw data from which the parameters are calculated must be included in the test report.
(C) Measurement location descriptions for both emission measurements and flare operating parameters.
(D) Description of sampling and analysis procedures (including number and length of test runs) and any modifications to standard procedures. If there were deviations from the approved test plan, a detailed description of the deviations and rationale why the test results or calculation procedures used are appropriate.
(E) Operating conditions (
(F) Quality assurance procedures.
(G) Records of calibrations.
(H) Raw data sheets for field sampling.
(I) Raw data sheets for field and laboratory analyses.
(J) Documentation of calculations.
(iii) The selected flare-specific operating limit values based on the performance evaluation test results, including the averaging time for the operating limit(s), and rationale why the selected values and averaging times are sufficiently stringent to ensure proper flare performance. If new operating parameters or averaging times are proposed for use other than those specified in paragraphs (d) through (f) of this section, an explanation of why the
(iv) The means by which the owner or operator will document on-going, continuous compliance with the selected flare-specific operating limit(s), including the specific measurement location and frequencies, calculation procedures, and records to be maintained.
(3) The request shall be submitted as described in paragraphs (r)(3)(i) through (iv) of this section.
(i) The owner or operator may request approval from the Administrator at any time upon completion of a performance evaluation conducted following the methods in an approved site-specific performance evaluation plan for an operating limit(s) that shall apply specifically to that flare.
(ii) The request must be submitted to the Administrator for approval. The owner or operator must continue to comply with the applicable standards for flares in this subpart until the requirements in § 63.6(g)(1) are met and a notice is published in the
(iii) The request shall also be submitted to the following address: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (E143-01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be submitted to
(iv) If the Administrator finds any deficiencies in the request, the request must be revised to address the deficiencies and be re-submitted for approval within 45 days of receipt of the notice of deficiencies. The owner or operator must comply with the revised request as submitted until it is approved.
(4) The approval process for a request for a flare-specific operating limit(s) is described in paragraphs (r)(4)(i) through (iii) of this section.
(i) Approval by the Administrator of a flare-specific operating limit(s) request will be based on the completeness, accuracy and reasonableness of the request. Factors that the EPA will consider in reviewing the request for approval include, but are not limited to, those described in paragraphs (r)(4)(i)(A) through (C) of this section.
(A) The description of the flare design and operating characteristics.
(B) If a new operating parameter(s) other than those specified in paragraphs (d) through (f) of this section is proposed, the explanation of how the proposed operating parameter(s) serves a good indicator(s) of flare combustion performance.
(C) The results of the flare performance evaluation test runs and the establishment of operating limits that ensures that the flare destruction efficiency is 98 percent or greater or that the flare combustion efficiency is 96.5 percent or greater at all times.
(D) The completeness of the flare performance evaluation test report.
(ii) If the request is approved by the Administrator, a flare-specific operating limit(s) will be established at the level(s) demonstrated in the approved request.
(iii) If the Administrator finds any deficiencies in the request, the request must be revised to address the deficiencies and be re-submitted for approval.
(a)
(1) Except for CPMS installed for pilot flame monitoring, all monitoring equipment must meet the applicable minimum accuracy, calibration and quality control requirements specified in table 13 of this subpart.
(2) The owner or operator shall ensure the readout (that portion of the CPMS that provides a visual display or record) or other indication of the monitored operating parameter from any CPMS required for compliance is readily accessible onsite for operational control or inspection by the operator of the source.
(3) All CPMS must complete a minimum of one cycle of operation (sampling, analyzing and data recording) for each successive 15-minute period.
(4) Except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions and required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments), the owner or operator shall operate all CPMS and collect data continuously at all times when regulated emissions are routed to the flare.
(5) The owner or operator shall operate, maintain, and calibrate each CPMS according to the CPMS monitoring plan specified in paragraph (b) of this section.
(6) For each CPMS except for CPMS installed for pilot flame monitoring, the owner or operator shall comply with the out-of-control procedures described in paragraph (c) of this section.
(7) The owner or operator shall reduce data from a CPMS as specified in paragraph (d) of this section.
(8) The CPMS must be capable of measuring the appropriate parameter over the range of values expected for that measurement location. The data recording system associated with each CPMS must have a resolution that is equal to or better than the required system accuracy.
(b)
(1) Identification of the specific flare being monitored and the flare type (air-assisted only, steam-assisted only, air- and steam-assisted, pressure-assisted, or non-assisted).
(2) Identification of the parameter to be monitored by the CPMS and the expected parameter range, including worst case and normal operation.
(3) Description of the monitoring equipment, including the information specified in paragraphs (b)(3)(i) through (vii) of this section.
(i) Manufacturer and model number for all monitoring equipment components installed to comply with applicable provisions in § 63.670.
(ii) Performance specifications, as provided by the manufacturer, and any differences expected for this installation and operation.
(iii) The location of the CPMS sampling probe or other interface and a justification of how the location meets the requirements of paragraph (a)(1) of this section.
(iv) Placement of the CPMS readout, or other indication of parameter values, indicating how the location meets the requirements of paragraph (a)(2) of this section.
(v) Span of the CPMS. The span of the CPMS sensor and analyzer must encompass the full range of all expected values.
(vi) How data outside of the span of the CPMS will be handled and the corrective action that will be taken to reduce and eliminate such occurrences in the future.
(vii) Identification of the parameter detected by the parametric signal analyzer and the algorithm used to convert these values into the operating parameter monitored to demonstrate compliance, if the parameter detected is different from the operating parameter monitored.
(4) Description of the data collection and reduction systems, including the information specified in paragraphs (b)(4)(i) through (iii) of this section.
(i) A copy of the data acquisition system algorithm used to reduce the measured data into the reportable form of the standard and to calculate the applicable averages.
(ii) Identification of whether the algorithm excludes data collected during CPMS breakdowns, out-of-control periods, repairs, maintenance periods, instrument adjustments or checks to maintain precision and accuracy, calibration checks, and zero (low-level), mid-level (if applicable) and high-level adjustments.
(iii) If the data acquisition algorithm does not exclude data collected during CPMS breakdowns, out-of-control periods, repairs, maintenance periods, instrument adjustments or checks to maintain precision and accuracy, calibration checks, and zero (low-level), mid-level (if applicable) and high-level adjustments, a description of the procedure for excluding this data when the averages calculated as specified in paragraph (e) of this section are determined.
(5) Routine quality control and assurance procedures, including descriptions of the procedures listed in paragraphs (b)(5)(i) through (vi) of this section and a schedule for conducting these procedures. The routine procedures must provide an assessment of CPMS performance.
(i) Initial and subsequent calibration of the CPMS and acceptance criteria.
(ii) Determination and adjustment of the calibration drift of the CPMS.
(iii) Daily checks for indications that the system is responding. If the CPMS system includes an internal system check, the owner or operator may use the results to verify the system is responding, as long as the system provides an alarm to the owner or operator or the owner or operator checks the internal system results daily for proper operation and the results are recorded.
(iv) Preventive maintenance of the CPMS, including spare parts inventory.
(v) Data recording, calculations and reporting.
(vi) Program of corrective action for a CPMS that is not operating properly.
(c)
(1) A CPMS is out-of-control if the zero (low-level), mid-level (if applicable) or high-level calibration drift exceeds two times the accuracy requirement of table 13 of this subpart.
(2) When the CPMS is out of control, the owner or operator shall take the necessary corrective action and repeat all necessary tests that indicate the system is out of control. The owner or operator shall take corrective action and conduct retesting until the performance requirements are below the applicable limits. The beginning of the out-of-control period is the hour a performance check (
(d)
(1) The owner or operator may round the data to the same number of significant digits used in that operating limit.
(2) Periods of non-operation of the process unit (or portion thereof) resulting in cessation of the emissions to which the monitoring applies must not be included in the 15-minute block averages.
(3) Periods when the CPMS is out of control must not be included in the 15-minute block averages.
(e)
(1) The quality assurance requirements are in table 13 of this subpart.
(2) The calibration gases must meet one of the following options:
(i) The owner or operator must use a calibration gas or multiple gases that include all of compounds listed in paragraphs (e)(2)(i)(A) through (K) of this section that may be reasonably expected to exist in the flare gas stream and optionally include any of the compounds listed in paragraphs (e)(2)(i)(L) through (O) of this section. All of the calibration gases may be combined in one cylinder. If multiple calibration gases are necessary to cover all compounds, the owner or operator must calibrate the instrument on all of the gases.
(A) Hydrogen.
(B) Methane.
(C) Ethane.
(D) Ethylene.
(E) Propane.
(F) Propylene.
(G) n-Butane.
(H) iso-Butane.
(I) Butene (general). It is not necessary to separately speciate butene isomers, but the net heating value of trans-butene must be used for co-eluting butene isomers.
(J) 1,3-Butadiene. It is not necessary to separately speciate butadiene isomers, but you must use the response factor and net heating value of 1,3-butadiene for co-eluting butadiene isomers.
(K) n-Pentane. Use the response factor for n-pentane to quantify all C5+ hydrocarbons.
(L) Acetylene (optional).
(M) Carbon monoxide (optional).
(N) Propadiene (optional).
(O) Hydrogen sulfide (optional).
(ii) The owner or operator must use a surrogate calibration gas consisting of hydrogen and C1 through C5 normal hydrocarbons. All of the calibration gases may be combined in one cylinder. If multiple calibration gases are necessary to cover all compounds, the owner or operator must calibrate the instrument on all of the gases.
(3) If the owner or operator chooses to use a surrogate calibration gas under paragraph (e)(2)(ii) of this section, the owner or operator must comply with paragraphs (e)(3)(i) and (ii) of this section.
(i) Use the response factor for the nearest normal hydrocarbon (
(ii) Use the response factor for n-pentane to quantify unknown
The revisions and additions read as follows:
The revisions and additions read as follows:
(b) * * *
(3) The process vent or group of process vents on Claus or other types of sulfur recovery plant units or the tail gas treatment units serving sulfur recovery plants that are associated with sulfur recovery.
(f) * * *
(5) Gaseous streams routed to a fuel gas system, provided that on and after January 30, 2019, any flares receiving gas from the fuel gas system are subject to § 63.670.
The revisions and additions read as follows:
(a) * * *
(1) Except as provided in paragraph (a)(5) of this section, meet each emission limitation in Table 1 of this subpart that applies to you. If your catalytic cracking unit is subject to the NSPS for PM in § 60.102 of this chapter or is subject to § 60.102a(b)(1) of this chapter, you must meet the emission limitations for NSPS units. If your catalytic cracking unit is not subject to the NSPS for PM, you can choose from the four options in paragraphs (a)(1)(i) through (vi) of this section:
(i) You can elect to comply with the NSPS for PM in § 60.102 of this chapter (Option 1a);
(ii) You can elect to comply with the NSPS for PM coke burn-off emission limit in § 60.102a(b)(1) of this chapter (Option 1b);
(iii) You can elect to comply with the NSPS for PM concentration limit in § 60.102a(b)(1) of this chapter (Option 1c);
(iv) You can elect to comply with the PM per coke burn-off emission limit in § 60.102a(b)(1) of this chapter (Option 2);
(v) You can elect to comply with the Nickel (Ni) lb/hr emission limit (Option 3); or
(vi) You can elect to comply with the Ni per coke burn-off emission limit (Option 4).
(2) Comply with each operating limit in Table 2 of this subpart that applies to you. When a specific control device may be monitored using more than one continuous parameter monitoring system, you may select the parameter with which you will comply. You must provide notice to the Administrator (or other designated authority) if you elect to change the monitoring option.
(5) During periods of startup, shutdown and hot standby, you can choose from the two options in paragraphs (a)(5)(i) and (ii) of this section:
(i) You can elect to comply with the requirements in paragraphs (a)(1) and (2) of this section, except catalytic cracking units controlled using a wet scrubber must maintain only the liquid to gas ratio operating limit (the pressure drop operating limit does not apply); or
(ii) You can elect to maintain the inlet velocity to the primary internal cyclones of the catalytic cracking unit catalyst regenerator at or above 20 feet per second.
(b) * * *
(2) Conduct a performance test for each catalytic cracking unit according to the requirements in § 63.1571 and under the conditions specified in Table 4 of this subpart.
(4) * * *
(i) If you elect Option 1b or Option 2 in paragraph (a)(1)(ii) or (iv) of this section, compute the PM emission rate (lb/1,000 lb of coke burn-off) for each run using Equations 1, 2, and 3 (if applicable) of this section and the site-specific opacity limit, if applicable, using Equation 4 of this section as follows:
(ii) If you elect Option 1c in paragraph (a)(1)(iii) of this section, the PM concentration emission limit, determine the average PM concentration from the initial performance test used to certify your PM CEMS.
(iv) If you elect Option 4 in paragraph (a)(1)(vi) of this section, the Ni per coke burn-off emission limit, compute your Ni emission rate using Equations 1 and 8 of this section and your site-specific Ni operating limit (if you use a continuous opacity monitoring system) using Equations 9 and 10 of this section as follows:
(c) * * *
(5) If you elect to comply with the alternative limit in paragraph (a)(5)(ii) of this section during periods of startup, shutdown, and hot standby, demonstrate continuous compliance by:
(i) Collecting the volumetric flow rate from the catalyst regenerator (in acfm) and determining the average flow rate for each hour. For events lasting less than one hour, determine the average flow rate during the event.
(ii) Determining the cumulative cross-sectional area of the primary internal cyclone inlets in square feet (ft
(iii) Calculating the inlet velocity to the primary internal cyclones in square feet per second (ft
(iv) Maintaining the inlet velocity to the primary internal cyclones at or above 20 feet per second for each hour during the startup, shutdown, or hot standby event or, for events lasting less than 1 hour, for the duration of the event.
(a) * * *
(1) Except as provided in paragraph (a)(5) of this section, meet each emission limitation in Table 8 of this subpart that applies to you. If your catalytic cracking unit is subject to the NSPS for carbon monoxide (CO) in § 60.103 of this chapter or is subject to § 60.102a(b)(4) of this chapter, you must meet the emission limitations for NSPS units. If your catalytic cracking unit is not subject to the NSPS for CO, you can choose from the two options in paragraphs (a)(1)(i) through (ii) of this section:
(5) During periods of startup, shutdown and hot standby, you can choose from the two options in paragraphs (a)(5)(i) and (ii) of this section:
(i) You can elect to comply with the requirements in paragraphs (a)(1) and (2) of this section; or
(ii) You can elect to maintain the oxygen (O
(a) * * *
(1) Meet each emission limitation in Table 15 of this subpart that applies to you. You can choose from the two options in paragraphs (a)(1)(i) and (ii) of this section.
(i) You can elect to vent emissions of total organic compounds (TOC) to a flare (Option 1). On and after January 30, 2019, the flare must meet the requirements of § 63.670. Prior to January 30, 2019, the flare must meet the control device requirements in § 63.11(b) or the requirements of § 63.670.
(4) The emission limitations in Tables 15 and 16 of this subpart do not apply to emissions from process vents during passive depressuring when the reactor vent pressure is 5 pounds per square inch gauge (psig) or less. The emission limitations in Tables 15 and 16 of this subpart do apply to emissions from process vents during active purging operations (when nitrogen or other purge gas is actively introduced to the reactor vessel) or active depressuring (using a vacuum pump, ejector system, or similar device) regardless of the reactor vent pressure.
(a) * * *
(1) Meet each emission limitation in Table 29 of this subpart that applies to you. If your sulfur recovery unit is subject to the NSPS for sulfur oxides in § 60.104 or § 60.102a(f)(1) of this chapter, you must meet the emission limitations for NSPS units. If your sulfur recovery unit is not subject to one of these NSPS for sulfur oxides, you can choose from the options in paragraphs (a)(1)(i) through (ii) of this section:
(i) You can elect to meet the NSPS requirements in § 60.104(a)(2) or § 60.102a(f)(1) of this chapter (Option 1); or
(4) During periods of startup and shutdown, you can choose from the three options in paragraphs (a)(4)(i) through (iii) of this section.
(i) You can elect to comply with the requirements in paragraphs (a)(1) and (2) of this section.
(ii) You can elect to send any startup or shutdown purge gases to a flare. On and after January 30, 2019, the flare must meet the requirements of § 63.670. Prior to January 30, 2019, the flare must meet the design and operating requirements in § 63.11(b) or the requirements of § 63.670.
(iii) You can elect to send any startup or shutdown purge gases to a thermal oxidizer or incinerator operated at a
(a) You must be in compliance with all of the non-opacity standards in this subpart at all times.
(b) You must be in compliance with the opacity and visible emission limits in this subpart at all times.
(c) At all times, you must operate and maintain any affected source, including associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices for minimizing emissions. The general duty to minimize emissions does not require you to make any further efforts to reduce emissions if levels required by the applicable standard have been achieved. Determination of whether a source is operating in compliance with operation and maintenance requirements will be based on information available to the Administrator which may include, but is not limited to, monitoring results, review of operation and maintenance procedures, review of operation and maintenance records, and inspection of the source.
(d) During the period between the compliance date specified for your affected source and the date upon which continuous monitoring systems have been installed and validated and any applicable operating limits have been set, you must maintain a log that documents the procedures used to minimize emissions from process and emissions control equipment according to the general duty in paragraph (c) of this section.
The revisions and additions read as follows:
(a) * * *
(5)
(i) Catalytic cracking units monitoring PM concentration with a PM CEMS are not required to conduct a periodic PM performance test.
(ii) Conduct a performance test annually if you comply with the emission limits in Item 1 (NSPS subpart J) or Item 4 (Option 1a) in Table 1 of this subpart and the PM emissions measured during the most recent performance source test are greater than 0.80 g/kg coke burn-off.
(6)
(i) If you conducted a performance test for HCN for a specific catalytic cracking unit between March 31, 2011 and February 1, 2016, you may submit a request to the Administrator to use the previously conducted performance test results to fulfill the one-time performance test requirement for HCN for each of the catalytic cracking units tested according to the requirements in paragraphs (a)(6)(i)(A) through (D) of this section.
(A) The request must include a copy of the complete source test report, the date(s) of the performance test and the test methods used. If available, you must also indicate whether the catalytic cracking unit catalyst regenerator was operated in partial or complete combustion mode during the test, the control device configuration, including whether platinum or palladium combustion promoters were used during the test, and the CO concentration (measured using CO CEMS or manual test method) for each test run.
(B) You must submit a separate request for each catalytic cracking unit tested and you must submit each request to the Administrator no later than March 30, 2016.
(C) The Administrator will evaluate each request with respect to the completeness of the request, the completeness of the submitted test report and the appropriateness of the test methods used. The Administrator will notify the facility within 60 days of receipt of the request if it is approved or denied. If the Administrator fails to respond to the facility within 60 days of receipt of the request, the request will be automatically approved.
(D) If the request is approved, you do not need to conduct an additional HCN performance test. If the request is denied, you must conduct an additional HCN performance test following the requirements in (a)(6)(ii) of this section.
(ii) Unless you receive approval to use a previously conducted performance test to fulfill the one-time performance test requirement for HCN for your catalytic cracking unit as provided in paragraph (a)(6)(i) of this section, conduct a performance test for HCN for each catalytic cracking unit no later than August 1, 2017 according to following requirements:
(A) Select sampling port location, determine volumetric flow rate, conduct gas molecular weight analysis and measure moisture content as specified in either Item 1 of Table 4 of this subpart or Item 1 of Table 11 of this subpart.
(B) Measure HCN concentration using Method 320 of appendix A of this part. The method ASTM D6348-03 (Reapproved 2010) including Annexes A1 through A8 (incorporated by reference—see § 63.14) is an acceptable alternative to EPA Method 320 of appendix A of this part. The method ASTM D6348-12e1 (incorporated by reference—see § 63.14) is an acceptable alternative to EPA Method 320 of appendix A of this part with the following two caveats:
(
(
(C) Measure CO concentration as specified in either Item 2 or 3a of Table 11 of this subpart.
(D) Record and include in the test report an indication of whether the catalytic cracking unit catalyst regenerator was operated in partial or complete combustion mode and the control device configuration, including whether platinum or palladium combustion promoters were used during the test.
(b) * * *
(1) Performance tests shall be conducted according to the provisions of § 63.7(e) except that performance tests shall be conducted at maximum representative operating capacity for the process. During the performance test, you must operate the control device at either maximum or minimum representative operating conditions for monitored control device parameters, whichever results in lower emission reduction. You must not conduct a performance test during startup, shutdown, periods when the control device is bypassed or periods when the process, monitoring equipment or control device is not operating properly. You may not conduct performance tests during periods of malfunction. You must record the process information that is necessary to document operating conditions during the test and include in such record an explanation to support that the test was conducted at maximum representative operating capacity. Upon request, you must make available to the Administrator such records as may be necessary to determine the conditions of performance tests.
(d) * * *
(2) If you must meet the HAP metal emission limitations in § 63.1564, you elect the option in paragraph (a)(1)(iv) in § 63.1564 (Ni per coke burn-off), and you use continuous parameter monitoring systems, you must establish an operating limit for the equilibrium catalyst Ni concentration based on the laboratory analysis of the equilibrium catalyst Ni concentration from the initial performance test. * * *
(4) Except as specified in paragraph (d)(3) of this section, if you use continuous parameter monitoring systems, you may adjust one of your monitored operating parameters (flow rate, total power and secondary current, pressure drop, liquid-to-gas ratio) from the average of measured values during the performance test to the maximum value (or minimum value, if applicable) representative of worst-case operating conditions, if necessary. This adjustment of measured values may be done using control device design specifications, manufacturer recommendations, or other applicable information. You must provide supporting documentation and rationale in your Notification of Compliance Status, demonstrating to the satisfaction of your permitting authority, that your affected source complies with the applicable emission limit at the operating limit based on adjusted values.
(c) Except for flare monitoring systems, you must install, operate, and maintain each continuous parameter monitoring system according to the requirements in paragraphs (c)(1) through (5) of this section. For flares, on and after January 30, 2019, you must install, operate, calibrate, and maintain monitoring systems as specified in §§ 63.670 and 63.671. Prior to January 30, 2019, you must either meet the monitoring system requirements in paragraphs (c)(1) through (5) of this section or meet the requirements in §§ 63.670 and 63.671.
(1) You must install, operate, and maintain each continuous parameter monitoring system according to the requirements in Table 41 of this subpart. You must also meet the equipment specifications in Table 41 of this subpart if pH strips or colormetric tube sampling systems are used. You must install, operate, and maintain each continuous parameter monitoring system according to the requirements in Table 41 of this subpart. You must meet the requirements in Table 41 of this subpart for BLD systems. Alternatively, before August 1, 2017, you may install, operate, and maintain each continuous parameter monitoring system in a manner consistent with the manufacturer's specifications or other written procedures that provide adequate assurance that the equipment will monitor accurately.
(3) Each continuous parameter monitoring system must have valid hourly average data from at least 75 percent of the hours during which the process operated, except for BLD systems.
(4) Each continuous parameter monitoring system must determine and record the hourly average of all recorded readings and if applicable, the daily average of all recorded readings for each operating day, except for BLD systems. The daily average must cover a 24-hour period if operation is continuous or the number of hours of operation per day if operation is not continuous, except for BLD systems.
(d) * * *
(1) You must conduct all monitoring in continuous operation (or collect data at all required intervals) at all times the affected source is operating.
(2) You may not use data recorded during required quality assurance or control activities (including, as applicable, calibration checks and required zero and span adjustments) for purposes of this regulation, including data averages and calculations, for fulfilling a minimum data availability requirement, if applicable. You must use all the data collected during all other periods in assessing the operation of the control device and associated control system.
The revisions and additions read as follows:
(b)
(1) Conduct a daily check of the air or water pressure to the spray nozzles;
(2) Maintain records of the results of each daily check; and
(3) Repair or replace faulty (
(c)
(d)
(f)
(g) * * *
(1) You may request alternative monitoring requirements according to the procedures in this paragraph if you meet each of the conditions in paragraphs (g)(1)(i) through (iii) of this section:
(a) * * *
(3) If you are required to conduct an initial performance test, performance evaluation, design evaluation, opacity observation, visible emission observation, or other initial compliance demonstration, you must submit a notification of compliance status according to § 63.9(h)(2)(ii). You can submit this information in an operating permit application, in an amendment to an operating permit application, in a separate submission, or in any combination. In a State with an approved operating permit program where delegation of authority under section 112(l) of the CAA has not been requested or approved, you must provide a duplicate notification to the applicable Regional Administrator. If the required information has been submitted previously, you do not have to provide a separate notification of compliance status. Just refer to the earlier submissions instead of duplicating and resubmitting the previously submitted information.
(f) * * *
(1) You must submit the plan to your permitting authority for review and approval along with your notification of compliance status. While you do not have to include the entire plan in your permit under part 70 or 71 of this chapter, you must include the duty to prepare and implement the plan as an applicable requirement in your part 70 or 71 operating permit. You must submit any changes to your permitting authority for review and approval and comply with the plan as submitted until the change is approved.
The revisions and additions read as follows:
(d) For each deviation from an emission limitation and for each deviation from the requirements for work practice standards that occurs at an affected source where you are not using a continuous opacity monitoring system or a continuous emission monitoring system to comply with the emission limitation or work practice standard in this subpart, the semiannual compliance report must contain the information in paragraphs (c)(1) through (3) of this section and the information in paragraphs (d)(1) through (4) of this section.
(1) The total operating time of each affected source during the reporting period and identification of the sources for which there was a deviation.
(2) Information on the number, date, time, duration, and cause of deviations (including unknown cause, if applicable).
(4) The applicable operating limit or work practice standard from which you deviated and either the parameter monitor reading during the deviation or a description of how you deviated from the work practice standard.
(e) For each deviation from an emission limitation occurring at an affected source where you are using a continuous opacity monitoring system or a continuous emission monitoring system to comply with the emission limitation, you must include the information in paragraphs (c)(1) through (3) of this section, in paragraphs (d)(1) through (3) of this section, and in paragraphs (e)(2) through (13) of this section.
(4) An estimate of the quantity of each regulated pollutant emitted over the emission limit during the deviation, and a description of the method used to estimate the emissions.
(6) A breakdown of the total duration of the deviations during the reporting period and into those that are due to control equipment problems, process problems, other known causes, and other unknown causes.
(f) * * *
(1) You must include the information in paragraph (f)(1)(i) or (ii) of this section, if applicable.
(i) If you are complying with paragraph (k)(1) of this section, a summary of the results of any performance test done during the reporting period on any affected unit. Results of the performance test include the identification of the source tested, the date of the test, the percentage of emissions reduction or outlet pollutant concentration reduction (whichever is needed to determine compliance) for each run and for the average of all runs, and the values of the monitored operating parameters.
(ii) If you are not complying with paragraph (k)(1) of this section, a copy of any performance test done during the reporting period on any affected unit. The report may be included in the next semiannual compliance report. The copy must include a complete report for each test method used for a particular kind of emission point tested. For additional tests performed for a similar emission point using the same method, you must submit the results and any other information required, but a complete test report is not required. A complete test report contains a brief process description; a simplified flow diagram showing affected processes, control equipment, and sampling point locations; sampling site data; description of sampling and analysis procedures and any modifications to standard procedures; quality assurance procedures; record of operating conditions during the test; record of
(2) Any requested change in the applicability of an emission standard (
(k)
(1) Within 60 days after the date of completing each performance test as required by this subpart, you must submit the results of the performance tests following the procedure specified in either paragraph (k)(1)(i) or (ii) of this section.
(i) For data collected using test methods supported by the EPA's Electronic Reporting Tool (ERT) as listed on the EPA's ERT Web site (
(ii) For data collected using test methods that are not supported by the EPA's ERT as listed on the EPA's ERT Web site at the time of the test, you must submit the results of the performance test to the Administrator at the appropriate address listed in § 63.13.
(2) Within 60 days after the date of completing each CEMS performance evaluation required by § 63.1571(a) and (b), you must submit the results of the performance evaluation following the procedure specified in either paragraph (k)(2)(i) or (ii) of this section.
(i) For performance evaluations of continuous monitoring systems measuring relative accuracy test audit (RATA) pollutants that are supported by the EPA's ERT as listed on the EPA's ERT Web site at the time of the evaluation, you must submit the results of the performance evaluation to the EPA via the CEDRI. (CEDRI is accessed through the EPA's CDX.) Performance evaluation data must be submitted in a file format generated through the use of the EPA's ERT or an alternate file format consistent with the XML schema listed on the EPA's ERT Web site. If you claim that some of the performance evaluation information being submitted is CBI, you must submit a complete file generated through the use of the EPA's ERT or an alternate electronic file consistent with the XML schema listed on the EPA's ERT Web site, including information claimed to be CBI, on a compact disc, flash drive or other commonly used electronic storage media to the EPA. The electronic storage media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: Group Leader, Measurement Policy Group, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT or alternate file with the CBI omitted must be submitted to the EPA via the EPA's CDX as described earlier in this paragraph (k)(2)(i).
(ii) For any performance evaluations of continuous monitoring systems measuring RATA pollutants that are not supported by the EPA's ERT as listed on the EPA's ERT Web site at the time of the evaluation, you must submit the results of the performance evaluation to the Administrator at the appropriate address listed in § 63.13.
(a) * * *
(2) The records specified in paragraphs (a)(2)(i) through (iv) of this section.
(i) Record the date, time, and duration of each startup and/or shutdown period, recording the periods when the affected source was subject to the standard applicable to startup and shutdown.
(ii) In the event that an affected unit fails to meet an applicable standard, record the number of failures. For each failure record the date, time and duration of each failure.
(iii) For each failure to meet an applicable standard, record and retain a list of the affected sources or equipment, an estimate of the volume of each regulated pollutant emitted over any emission limit and a description of the method used to estimate the emissions.
(iv) Record actions taken to minimize emissions in accordance with § 63.1570(c) and any corrective actions taken to return the affected unit to its normal or usual manner of operation.
(b) * * *
(3) The performance evaluation plan as described in § 63.8(d)(2) for the life of the affected source or until the affected source is no longer subject to the provisions of this part, to be made available for inspection, upon request, by the Administrator. If the performance evaluation plan is revised, you must keep previous (
(5) Records of the date and time that each deviation started and stopped.
The revisions read as follows:
Terms used in this subpart are defined in the Clean Air Act (CAA), in 40 CFR 63.2, the General Provisions of
(1) Fails to meet any requirement or obligation established by this subpart, including but not limited to any emission limit, operating limit, or work practice standard; or
(2) Fails to meet any term or condition that is adopted to implement an applicable requirement in this subpart and that is included in the operating permit for any affected source required to obtain such a permit.
As stated in § 63.1564(a)(1), you shall meet each emission limitation in the following table that applies to you.
As stated in § 63.1564(a)(2), you shall meet each operating limit in the following table that applies to you.
As stated in § 63.1564(b)(1), you shall meet each requirement in the following table that applies to you.
As stated in §§ 63.1564(b)(2) and 63.1571(a)(5), you shall meet each requirement in the following table that applies to you.
As stated in § 63.1564(b)(5), you shall meet each requirement in the following table that applies to you.
As stated in § 63.1564(c)(1), you shall meet each requirement in the following table that applies to you.
As stated in § 63.1564(c)(1), you shall meet each requirement in the following table that applies to you.
As stated in § 63.1565(a)(1), you shall meet each emission limitation in the following table that applies to you.
As stated in § 63.1565(a)(2), you shall meet each operating limit in the following table that applies to you.
As stated in § 63.1565(b)(1), you shall meet each requirement in the following table that applies to you.
As stated in § 63.1565(b)(4), you shall meet each requirement in the following table that applies to you.
As stated in § 63.1565(c)(1), you shall meet each requirement in the following table that applies to you.
As stated in § 63.1565(c)(1), you shall meet each requirement in the following table that applies to you.
As stated in § 63.1568(a)(1), you shall meet each emission limitation in the following table that applies to you.
As stated in § 63.1568(a)(2), you shall meet each operating limit in the following table that applies to you.
As stated in § 63.1568(b)(1), you shall meet each requirement in the following table that applies to you.
As stated in § 63.1568(b)(2) and (3), you shall meet each requirement in the following table that applies to you.
As stated in § 63.1568(b)(5), you shall meet each requirement in the following table that applies to you.
As stated in § 63.1568(c)(1), you shall meet each requirement in the following table that applies to you.
As stated in § 63.1568(c)(1), you shall meet each requirement in the following table that applies to you.
As stated in § 63.1572(a)(1) and (b)(1), you shall meet each requirement in the following table that applies to you.
As stated in § 63.1572(c)(1), you shall meet each requirement in the following table that applies to you.
As stated in § 63.1575(a), you shall meet each requirement in the following table that applies to you.
As stated in § 63.1577, you shall meet each requirement in the following table that applies to you.
2.1 A representative sample of catalyst particles is collected, prepared, and analyzed for analyte concentration using either energy or wavelength dispersive X-ray fluorescent (XRF) spectrometry instrumental analyzers. * * *
7.1.3 Low-Range Calibration Standard. Concentration equivalent to 1 to 20 percent of the span. The concentration of the low-range calibration standard should be selected so that it is less than either one-fourth of the applicable concentration limit or of the lowest concentration anticipated in the catalyst samples.
Method 325A—Volatile Organic Compounds from Fugitive and Area Sources:
1.1 This method describes collection of volatile organic compounds (VOCs) at or inside a facility property boundary or from fugitive and area emission sources using passive (diffusive) tube samplers (PS). The concentration of airborne VOCs at or near these potential fugitive- or area-emission sources may be determined using this method in combination with Method 325B. Companion Method 325B (Sampler Preparation and Analysis) describes preparation of sampling tubes, shipment and storage of exposed sampling tubes, and analysis of sampling tubes collected using either this passive sampling procedure or alternative active (pumped) sampling methods.
1.2 This method may be used to determine the average concentration of the select VOCs using the corresponding uptake rates listed in Method 325B, Table 12.1. Additional compounds or alternative sorbents must be evaluated as described in Addendum A of Method 325B or by one of the following national/international standard methods: ISO 16017-2:2003(E), ASTM D6196-03 (Reapproved 2009), or BS EN 14662-4:2005 (all incorporated by reference—see § 63.14), or reported in the peer-reviewed open literature.
1.3 Methods 325A and 325B are valid for the measurement of benzene. Supporting literature (References 1-8) indicates that benzene can be measured by flame ionization detection or mass spectrometry over a concentration range of approximately 0.5 micrograms per cubic meter (µg/m
1.4 This method may be applied to screening average airborne VOC concentrations at facility property boundaries or monitoring perimeters over an extended period of time using multiple sampling periods (
1.5 This method requires the collection of local meteorological data (wind speed and direction, temperature, and barometric pressure). Although local meteorology is a component of this method, non-regulatory applications of this method may use regional meteorological data. Such applications risk that the results may not identify the precise source of the emissions.
The diffusive passive sampler collects VOC from air for a measured time period at a rate that is proportional to the concentration of vapor in the air at that location.
2.1.1 This method describes the deployment of prepared passive samplers, including determination of the number of passive samplers needed for each survey and placement of samplers along or inside the facility property boundary depending on the size and shape of the site or linear length of the boundary.
2.1.2 The rate of sampling is specific to each compound and depends on the diffusion constants of that VOC and the sampler dimensions/characteristics as determined by prior calibration in a standard atmosphere (Reference 1).
2.1.3 The gaseous VOC target compounds migrate through a constant diffusion barrier (
2.1.4 Heat and a flow of inert carrier gas are then used to extract (desorb) the retained VOCs back from the sampling end of the tube and transport/transfer them to a gas chromatograph (GC) equipped with a chromatographic column to separate the VOCs and a detector to determine the quantity of target VOCs.
2.1.5 Gaseous or liquid calibration standards loaded onto the sampling ends of clean sorbent tubes must be used to calibrate the analytical equipment.
2.1.6 This method requires the use of field blanks to ensure sample integrity associated with shipment, collection, and storage of the passive samples. It also requires the use of field duplicates to validate the sampling process.
2.1.7 At the end of each sampling period, the passive samples are collected, sealed, and shipped to a laboratory for analysis of target VOCs by thermal desorption gas chromatography, as described in Method 325B.
2.2.1 This method requires deployment of passive sampling tubes on a monitoring perimeter encompassing all known emission sources at a facility and collection of local meteorological data. It may be used to determine average concentration of VOC at a facility's “fenceline” using time integrated passive sampling (Reference 2).
2.2.2 Collecting samples and meteorological data at progressively higher frequencies may be employed to resolve shorter term concentration fluctuations and wind conditions that could introduce interfering emissions from other sources.
2.2.3 This passive sampling method provides a low cost approach to screening of fugitive or area emissions compared to active sampling methods that are based on pumped sorbent tubes or time weighted average canister sampling.
2.2.3.1 Additional passive sampling tubes may be deployed at different distances from the facility property boundary or from the geometric center of the fugitive emission source.
2.2.3.2 Additional meteorological measurements may also be collected as needed to perform preliminary gradient-based assessment of the extent of the pollution plume at ground level and the effect of “background” sources contributing to airborne VOC concentrations at the location.
2.2.4 Time-resolved concentration measurements coupled with time-resolved meteorological monitoring may be used to generate data needed for source apportionment procedures and mass flux calculations.
(See also Section 3.0 of Method 325B.)
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
Glass and glass- (or fused silica-) lined stainless steel sorbent tubes (typically 4 mm i.d.) are also available in various lengths to suit different makes of thermal desorption equipment, but these are rarely used for passive sampling because it is more difficult to adequately define the diffusive air gap in glass or glass-line tubing. Such tubes are not recommended for this method.
Passive tube samplers should be sited at a distance beyond the influence of possible obstructions such as trees, walls, or buildings at the monitoring site. Complex topography and physical site obstructions, such as bodies of water, hills, buildings, and other structures that may prevent access to a planned PS location must be taken into consideration. You must document and report siting interference with the results of this method.
Nearby or upwind sources of target emissions outside the facility being tested can contribute to background concentrations. Moreover, because passive samplers measure continuously, changes in wind direction can cause variation in the level of background concentrations from interfering sources during the monitoring period. This is why local meteorological information, particularly wind direction and speed, is required to be collected throughout the monitoring period. Interfering sources can include neighboring industrial facilities, transportation facilities, fueling operations, combustion sources, short-term transient sources, residential sources, and nearby highways or roads. As PS data are evaluated, the location of potential interferences with respect to PS locations and local wind conditions should be considered, especially when high PS concentration values are observed.
You must protect the PS tubes from gross external contamination during field sampling. Analytical thermal desorption equipment used to analyze PS tubes must desorb organic compounds from the interior of PS tubes and exclude contamination from external sampler surfaces in the analytical/sample flow path. If the analytical equipment does not comply with this requirement, you must wear clean, white, cotton or powder-free nitrile gloves to handle sampling tubes to prevent contamination of the external sampler surfaces. Sampling tubes must be capped with two-piece, brass, 0.25 inch, long-term storage caps fitted with combined polytetrafluoroethylene ferrules (see Section 6.1 and Method 325B) to prevent ingress of airborne contaminants outside the sampling period. When not being used for field monitoring, the capped tubes must be stored in a clean, air-tight, shipping container to prevent the collection of VOCs (see Section 6.4.2 of Method 325B).
Although air speeds are a constraint for many forms of passive samplers, axial tube PS devices have such a slow inherent uptake rate that they are largely immune to these effects (References 4,5). Passive samplers must nevertheless be deployed under non-emitting weatherproof hoods to moderate the effect of local weather conditions such as solar heating and rain. The cover must not impede the ingress of ambient air. Sampling tubes should also be orientated vertically and pointing downwards, to minimize accumulation of particulates.
The normal working range for field sampling for sorbent packing is 0-40 °C (References 6,7). Note that most published passive uptake rate data for sorbent tubes is quoted at 20 °C. Note also that, as a rough guide, an increase in temperature of 10 °C will reduce the collection capacity for a given analyte on a given sorbent packing by a factor of 2, but the uptake rate will not change significantly (Reference 4).
This method does not purport to include all safety issues or procedures needed when deploying or collecting passive sampling tubes. Precautions typical of field air sampling projects are required. Tripping, falling, electrical, and weather safety considerations must all be included in plans to deploy and collect passive sampling tubes.
This section describes the equipment and supplies needed to deploy passive sampling monitoring equipment at a facility property boundary. Details of the passive sampling tubes themselves and equipment required for subsequent analysis are described in Method 325B.
The industry standard PS tubes used in this method must meet the specific configuration and preparation requirements described in Section 3.0 of this method and Section 6.1 of Method 325B.
The use of PS tubes packed with various sorbent materials for monitoring a wide variety of organic compounds in ambient air has been documented in the literature (References 4-10). Other sorbents may be used in standard passive sampling tubes for monitoring additional target compound(s) once their uptake rate and performance has been demonstrated following procedures in Addendum A to Method 325B. Guidance on sorbent selection can also be obtained from relevant national and international standard methods such as ASTM D6196-03 (Reapproved 2009) (Reference 14) and ISO 16017-2:2003(E) (Reference 13) (both incorporated by reference—see § 63.14).
One diffusive sampling cap is required per PS tube. The cap fits onto the sampling end of the tube during air monitoring. The other end of the tube remains sealed with the long-term storage cap. Each diffusive sampling cap is fitted with a stainless steel gauze, which defines the outer limit of the diffusion air gap.
A simple weatherproof hood, suitable for protecting passive sampling tubes from the worst of the weather (see Section 4.4) consists of an inverted cone/funnel constructed of an inert, non-outgassing material that fits over the diffusive tube, with the open (sampling) end of the tube projecting just below the cone opening. An example is shown in Figure 6.1 (Adapted from Reference 13).
If the analytical thermal desorber that will subsequently be used to analyze the passive sampling tubes does not meet the requirement to exclude outer surface contaminants from the sample flow path (see Section 6.6 of Method 325B), then clean, white, cotton or powder-free nitrile gloves must be used for handling the passive sampling tubes during field deployment.
Sorbent tube configurations, sorbents or other VOC not listed in this method must be evaluated according to Method 325B, Addendum A or ISO 16017-2:2003(E) (Reference 13) (incorporated by reference—see § 63.14). The supporting evaluation and verification data described in Method 325B, Addendum A for configurations or compounds different from the ones described in this method must meet the performance requirements of Method 325A/B and must be submitted with the test plan for your measurement program.
No reagents or standards are needed for the field deployment and collection of passive sampling tubes. Specifications for sorbents, gas and liquid phase standards, preloaded standard tubes, and carrier gases are covered in Section 7 of Method 325B.
Pre-deployment and planning steps are required before field deployment of passive sampling tubes. These activities include but are not limited to conducting a site visit, determining suitable and required monitoring locations, and determining the monitoring frequency to be used.
8.1.1 Determine the size and shape of the facility footprint in order to determine the required number of monitoring locations.
8.1.2 Identify obstacles or obstructions (buildings, roads, fences), hills and other terrain issues (
8.1.3 Identify to the extent possible and record potential off-site source interferences (
8.1.4 Identify the closest available meteorological station. Identify potential locations for one or more on-site or near-site meteorological station(s) following the guidance in EPA-454/B-08-002 (Reference 11) (incorporated by reference—see § 63.14).
8.2.1 The number and placement of the passive samplers depends on the size, the shape of the facility footprint or the linear distance around the facility, and the proximity of emission sources near the property boundaries. Aerial photographs or site maps may be used to determine the size (acreage) and shape of the facility or the length of the monitoring perimeter. Place passive samplers on an internal monitoring perimeter on or inside the facility boundary encompassing all emission sources at the facility at different angles circling the geometric center of the facility or at different distances based on the monitoring perimeter length of the facility.
In some instances, permanent air monitoring stations may already be located in close proximity to the facility. These stations may be operated and maintained by the site, or local or state regulatory agencies. If access to the station is possible, a PS may be deployed adjacent to other air monitoring instrumentation. A comparison of the pollutant concentrations measured with the PS to concentrations measured by site instrumentation may be used as an optional data quality indicator to assess the accuracy of PS results.
8.2.1.1 The monitoring perimeter may be located between the property boundary and any potential emission source near the property boundary, as long as the distance from the source to the monitoring perimeter is at least 50 meters (162 feet). If a potential emissions source is within 50 meters (162 feet) of the property boundary, the property boundary shall be used as the monitoring perimeter near that source.
8.2.1.2 Samplers need only be placed around the monitoring perimeter and not along internal roads or other right of ways that may bisect the facility.
8.2.1.3 Extra samplers must be placed near known sources of VOCs if the potential emission source is within 50 meters (162 feet) of the boundary and the source location is between two monitors. Measure the distance (x) between the two monitors and place another monitor halfway between (x/2) the two monitors. For example, in Figure 8.1, the facility added three additional monitors (
8.2.2 Option 1 for Determining Sampling Locations.
8.2.2.1 For facilities with a regular (circular, triangular, rectangular, or square) shape, determine the geographic center of the facility.
8.2.2.1.1 For facilities with an area of less than or equal to 750 acres, measure angles of 30 degrees from the center point for a total of twelve 30 degree measurements evenly spaced (±1 degree).
8.2.2.1.2 For facilities covering an area greater than 750 acres but less than or equal to 1,500 acres, measure angles of 20 degrees from the center point for a total of eighteen 20 degree measurements evenly spaced (±1 degree). Figure 8.1 shows the monitor placement around the property boundary of a facility with an area between 750 and 1,500 acres. Monitor placements are represented with black dots along the property boundary.
8.2.2.1.3 For facilities covering an area greater than 1,500 acres, measure angles of 15 degrees from the center point for a total of twenty-four 15 degree measurements evenly spaced (±1 degree).
8.2.2.1.4 Locate each sampling point where the measured angle intersects the outer monitoring perimeter.
8.2.2.2 For irregularly shaped facilities, divide the area into a set of connecting subarea circles, triangles or rectangles to determine sampling locations. The subareas must be defined such that a circle can reasonably encompass the subarea. Then determine the geometric center point of each of the subareas.
8.2.2.2.1 If a subarea is less than or equal to 750 acres (
8.2.2.2.2 If a subarea is greater than 750 acres but less than or equal to 1,500 acres (
8.2.2.2.3 If a subarea is greater than 1,500 acres, measure angles of 15 degrees from the center for a total of twenty-four 15 degree measurements (±1 degree).
8.2.2.2.4 Locate each sampling point where the measured angle intersects the outer monitoring perimeter. Sampling points need not be placed closer than 152 meters (500 feet) apart (or 76 meters (250 feet) if known sources are within 50 meters (162 feet) of the monitoring perimeter), as long as a minimum of 3 monitoring locations are used for each subarea.
8.2.2.2.5 Sampling sites are not needed at the intersection of an inner boundary with an adjacent subarea. The sampling location must be sited where the measured angle intersects the subarea's outer monitoring perimeter.
8.2.3 Option 2 for Determining Sampling Locations.
8.2.3.1 For facilities with a monitoring perimeter length of less than 7,315 meters (24,000 feet), a minimum of twelve sampling locations evenly spaced ±10 percent of the location interval is required.
8.2.3.2 For facilities with a monitoring perimeter length greater than 7,315 meters (24,000 feet), sampling locations are spaced 610 ±76 meters (2,000 ± 250 feet) apart.
A meteorological station is required at or near the facility you are monitoring. A number of commercially available meteorological stations can be used. Information on meteorological instruments can be found in EPA-454/R-99-005 (Reference 11) (incorporated by reference—see § 63.14). Some important considerations for siting of meteorological stations are detailed below.
8.3.1 Place meteorological stations in locations that represent conditions affecting the transport and dispersion of pollutants in the area of interest. Complex terrain may require the use of more than one meteorological station.
8.3.2 Deploy wind instruments over level, open terrain at a height of 10 meters (33 feet). If possible, locate wind instruments at a distance away from nearby structures that is equal to at least 10 times the height of the structure.
8.3.3 Protect meteorological instruments from thermal radiation and adequately ventilate them using aspirated shields. The temperature sensor must be located at a distance away from any nearby structures that is equal to at least four times the height of the structure. Temperature sensors must be located at least 30 meters (98 feet) from large paved areas.
8.3.4 Collect and record meteorological data, including wind speed, wind direction, temperature and barometric pressure on an hourly basis. Calculate average unit vector wind direction, sigma theta, temperature and barometric pressure per sampling period to enable calculation of concentrations at standard conditions. Supply this information to the laboratory.
8.3.5 Identify and record the location of the meteorological station by its GPS coordinate.
8.4.1 Sample collection may be performed for periods up to 14 days.
8.4.2 A site screening protocol that meets method requirements may be performed by collecting samples for a year where each PS accumulates VOC for a 14-day sampling period. Study results are accumulated for the sampling periods (typically 26) over the course of one calendar year. To the extent practical, sampling tubes should be changed at approximately the same time of day at each of the monitoring sites.
8.5.1 Clean (conditioned) sorbent tubes must be prepared and packaged by the laboratory as described in Method 325B and must be deployed for sampling within 30 days of conditioning.
8.5.2 Allow the tubes to equilibrate with ambient temperature (approximately 30 minutes to 1 hour) at the monitoring location before removing them from their storage/shipping container for sample collection.
8.5.3 If there is any risk that the analytical equipment will not meet the requirement to exclude contamination on outer tube surfaces from the sample flow path (see Section 6.6 of Method 325B), sample handlers must wear clean, white, cotton or powder-free nitrile gloves during PS deployment and collection and throughout any other tube handling operations.
8.5.4 Inspect the sampling tubes immediately prior to deployment. Ensure that they are intact, securely capped, and in good condition. Any suspect tubes (
8.5.5 Secure passive samplers so the bottom of the diffusive sampling cap is 1.5 to 3 meters (4.9 to 9.8 feet) above ground using a pole or other secure structure at each sampling location. Orient the PS vertically and with the sampling end pointing downward to avoid ingress of particulates.
Duplicate sampling assemblies must be deployed in at least one monitoring location for every 10 monitoring locations during each field monitoring period.
8.5.6 Protect the PS from rain and excessive wind velocity by placing them under the type of protective hood described in Section 6.1.3 or equivalent.
8.5.7 Remove the storage cap on the sampling end of the tube and replace it with a diffusive sampling cap at the start of the sampling period. Make sure the diffusion cap is properly seated and store the removed storage caps in the empty tube shipping container.
8.5.8 Record the start time and location details for each sampler on the field sample data sheet (see example in Section 17.0.).
8.5.9 Expose the sampling tubes for the required sampling period-normally 14-days.
8.5.10 Field blank tubes (see Section 9.3 of Method 325B) are stored outside the shipping container at representative sampling locations around the site, but with both long-term storage caps kept in place throughout the monitoring exercise. Collect at least two field blanks sorbent samples per sampling period to ensure sample integrity associated with shipment, collection, and storage.
Recover deployed sampling tubes and field blanks as follows:
8.6.1 After the sampling period is complete, immediately replace the diffusion end cap on each sampled tube with a long-term storage end cap. Tighten the seal securely by hand and then tighten an additional quarter turn with an appropriate tool. Record the stop date and time and any additional relevant information on the sample data sheet.
8.6.2 Place the sampled tubes, together with the field blanks, in the storage/shipping container. Label the storage container, but do not use paints, markers, or adhesive labels to identify the tubes. TD-compatible electronic (radio frequency identification (RFID)) tube labels are available commercially and are compatible with some brands of thermal desorber. If used, these may be programmed with relevant tube and sample information, which can be read and automatically transcribed into the sequence report by the TD system.
Sampled tubes must not be placed in the same shipping container as clean conditioned sampling tubes.
8.6.3 Sampled tubes may be shipped at ambient temperature to a laboratory for sample analysis.
8.6.4 Specify whether the tubes are field blanks or were used for sampling and document relevant information for each tube using a Chain of Custody form (see example in Section 17.0) that accompanies the samples from preparation of the tubes through receipt for analysis, including the following information: Unique tube identification numbers for each sampled tube; the date, time, and location code for each PS placement; the date, time, and location code for each PS recovery; the GPS reference for each sampling location; the unique identification number of the duplicate sample (if applicable); and problems or anomalies encountered.
8.6.5 If the sorbent tubes are supplied with electronic (
Sampling start and end times/dates can also be logged using RFID tube tags.
9.1 Most quality control checks are carried out by the laboratory and associated requirements are in Section 9.0 of Method 325B, including requirements for laboratory blanks, field blanks, and duplicate samples.
9.2 Evaluate for potential outliers the laboratory results for neighboring sampling tubes collected over the same time period. A potential outlier is a result for which one or more PS tube does not agree with the trend in results shown by neighboring PS tubes—particularly when data from those locations have been more consistent during previous sampling periods. Accidental contamination by the sample handler must be documented before any result can be eliminated as an outlier. Rare but possible examples of contamination include loose or missing storage caps or contaminated storage/shipping containers. Review data from the same and neighboring monitoring locations for the subsequent sampling periods. If the anomalous result is not repeated for that monitoring location, the episode can be ascribed to transient contamination and the data in question must be flagged for potential elimination from the dataset.
9.3.1 Collect at least one co-located/duplicate sample for every 10 field samples to determine precision of the measurements.
9.3.2 Collect at least two field blanks sorbent samples per sampling period to ensure sample integrity associated with shipment, collection, and storage. You must use the entire sampling apparatus for field blanks including unopened sorbent tubes mounted in protective sampling hoods. The tube closures must not be removed. Field blanks must be placed in two different quadrants (
Follow the calibration and standardization procedures for meteorological measurements in EPA-454/B-08-002 March 2008 (Reference 11) (incorporated by reference—see § 63.14). Refer to Method 325B for calibration and standardization procedures for analysis of the passive sampling tubes.
Refer to Method 325B, which provides details for the preparation and analysis of sampled passive monitoring tubes (preparation of sampling tubes, shipment and storage of exposed sampling tubes, and analysis of sampling tubes).
After a year's worth of sampling at the facility fenceline (for example, 26 14-day samples), the average (PS
PS
If data from neighboring sampling locations are significantly different, then you may add extra sampling points to isolate background contributions or identify facility-specific “hot spots.”
You may evaluate trends and patterns in the PS data over multiple sampling periods to determine if elevated concentrations of target compounds are due to operations on the facility or if contributions from background sources are significant.
12.3.1 Obtain meteorological data including wind speed and wind direction or unit vector wind data from the on-site meteorological station. Use this meteorological data to determine the prevailing wind direction and speed during the periods of elevated concentrations.
12.3.2 As an option you may perform preliminary back trajectory calculations (
12.3.3 Information on published or documented events on- and off-site may also be included in the associated sampling period report to explain elevated concentrations if relevant. For example, you would describe if there was a chemical spill on site, or an accident on an adjacent road.
12.3.4 Additional monitoring for shorter periods (See section 8.4) may be necessary to allow better discrimination/resolution of contributing emission sources if the measured trends and associated meteorology do not provide a clear assessment of facility contribution to the measured fenceline concentration.
12.3.5 Additional records necessary to calculate sampling period average target compound concentration can be found in Section 12.1 of Method 325B.
Method performance requirements are described in Method 325B.
[Reserved]
[Reserved]
1.1 This method describes thermal desorption/gas chromatography (TD/GC) analysis of volatile organic compounds (VOCs) from fugitive and area emission sources collected onto sorbent tubes using passive sampling. It could also be applied to the TD/GC analysis of VOCs collected using active (pumped) sampling onto sorbent tubes. The concentration of airborne VOCs at or near potential fugitive- or area-emission sources may be determined using this method in combination with Method 325A. Companion Method 325A (Sampler Deployment and VOC Sample Collection) describes procedures for deploying the sorbent tubes and passively collecting VOCs.
1.2 The preferred GC detector for this method is a mass spectrometer (MS), but flame ionization detectors (FID) may also be used. Other conventional GC detectors such as electron capture (ECD), photoionization (PID), or flame photometric (FPD) may also be used if they are selective and sensitive to the target compound(s) and if they meet the method performance criteria provided in this method.
1.3 There are 97 VOCs listed as hazardous air pollutants in Title III of the Clean Air Act Amendments of 1990. Many of these VOC are candidate compounds for this method. Compounds with known uptake rates for Carbograph
1.4 The analytical approach using TD/GC/MS is based on previously published EPA guidance in Compendium Method TO-17 (
1.5 Inorganic gases not suitable for analysis by this method include oxides of carbon, nitrogen and sulfur, ozone (O
2.1 This method provides procedures for the preparation, conditioning, blanking, and shipping of sorbent tubes prior to sample collection.
2.2 Laboratory and field personnel must have experience of sampling trace-level VOCs using sorbent tubes (References 2,5) and must have experience operating thermal desorption/GC/multi-detector instrumentation.
2.3 Key steps of this method as implemented for each sample tube include: Stringent leak testing under stop flow, recording ambient temperature conditions, adding internal standards, purging the tube, thermally desorbing the sampling tube, refocusing on a focusing trap, desorbing and transferring/injecting the VOCs from the secondary trap into the capillary GC column for separation and analysis.
2.4 Water management steps incorporated into this method include: (a) Selection of hydrophobic sorbents in the sampling tube; (b) optional dry purging of sample tubes prior to analysis; and (c) additional selective elimination of water during primary (tube) desorption (if required) by selecting trapping sorbents and temperatures such that target compounds are quantitatively retained while water is purged to vent.
(See also Section 3.0 of Method 325A).
3.1 Blanking is the desorption and confirmatory analysis of conditioned sorbent tubes before they are sent for field sampling.
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
3.11
3.12
3.13
3.14
3.15
3.16
3.17
4.1
4.1.1 Sorbent decomposition artifacts are VOCs that form when sorbents degenerate,
4.1.2 Preparation and storage artifacts are VOCs that were not completely cleaned from the sorbent tube during conditioning or that are an inherent feature of that sorbent at a given temperature.
4.2
4.3
5.1 This method does not address all of the safety concerns associated with its use. It is the responsibility of the user of this standard to establish appropriate field and laboratory safety and health practices prior to use.
5.2 Laboratory analysts must exercise extreme care in working with high-pressure gas cylinders.
5.3 Due to the high temperatures involved, operators must use caution when conditioning and analyzing tubes.
6.1
6.2.1 Freshly packed or newly purchased tubes must be conditioned as described in Section 9 using an appropriate dedicated tube conditioning unit or the thermal desorber. Note that the analytical TD system should be used for tube conditioning if it supports a dedicated tube conditioning mode in which effluent from contaminated tubes is directed to vent without passing through key parts of the sample flow path such as the focusing trap.
6.2.2 Dedicated tube conditioning units must be leak-tight to prevent air ingress, allow precise and reproducible temperature selection (±5 °C), offer a temperature range at least as great as that of the thermal desorber, and support inert gas flows in the range up to 100 mL/min.
For safety and to avoid laboratory contamination, effluent gases from freshly packed or highly contaminated tubes should be passed through a charcoal filter during the conditioning process to prevent desorbed VOCs from polluting the laboratory atmosphere.
6.3.1 Label the sample tubes with a unique permanent identification number and an indication of the sampling end of the tube. Labeling options include etching and TD-compatible electronic (radio frequency identification (RFID)) tube labels.
6.3.2 To avoid contamination, do not make ink markings of any kind on clean sorbent tubes or apply adhesive labels.
TD-compatible electronic (RFID) tube labels are available commercially and are compatible with some brands of thermal desorber. If used, these may be programmed with relevant tube and sample information, which can be read and automatically transcribed into the sequence report by the TD system (see Section 8.6 of Method 325A).
6.4.1 Long-term storage caps. Seal clean, blank and sampled sorbent tubes using inert, long-term tube storage caps comprising non-greased, 2-piece, 0.25-inch, metal SwageLok®-type screw caps fitted with combined polytetrafluoroethylene ferrules.
6.4.2 Storage and transportation containers. Use clean glass jars, metal cans or rigid, non-emitting polymer boxes.
You may add a small packet of new activated charcoal or charcoal/silica gel to the shipping container for storage and transportation of batches of conditioned sorbent tubes prior to use. Coolers without ice packs make suitable shipping boxes for containers of tubes because the coolers help to insulate the samples from extreme temperatures (
A suitable device has a simple push fit or finger-tightening connector for attaching the sampling end of blank sorbent tubes without damaging the tube. It also has a means of controlling carrier gas flow through the injector and attached sorbent tube at 50-100 mL/min and includes a low emission septum cap that allows the introduction of gas or liquid standards via appropriate syringes. Reproducible and quantitative transfer of higher boiling compounds in liquid standards is facilitated if the injection unit allows the tip of the syringe to just touch the sorbent retaining gauze inside the tube.
The manual or automated thermal desorption system must heat sorbent tubes while a controlled flow of inert (carrier) gas passes through the tube and out of the sampling end. The apparatus must also incorporate a focusing trap to quantitatively refocus compounds desorbed from the tube. Secondary desorption of the focusing trap should be fast/efficient enough to transfer the compounds into the high resolution capillary GC column without band broadening and without any need for further pre- or on-column focusing. Typical TD focusing traps comprise small sorbent traps (Reference 16) that are electrically-cooled using multistage Peltier cells (References 17, 18). The direction of gas flow during trap desorption should be the reverse of that used for focusing to extend the compatible analyte volatility range. Closed cycle coolers offer another cryogen-free trap cooling option. Other TD system requirements and operational stages are described in Section 11 and in Figures 17-2 through 17-4.
6.7.1 The interface between the thermal desorber and the GC must be heated uniformly and the connection between the transfer line insert and the capillary GC analytical column itself must be leak tight.
6.7.2 A portion of capillary column can alternatively be threaded through the heated transfer line/TD interface and connected directly to the thermal desorber.
Use of a metal syringe-type needle or unheated length of fused silica pushed through the septum of a conventional GC
6.8.1 The GC system must be capable of temperature programming and operation of a high resolution capillary column. Depending on the choice of column (
6.8.2 All carrier gas lines supplying the GC must be constructed from clean stainless steel or copper tubing. Non-polytetrafluoroethylene thread sealants. Flow controllers, cylinder regulators, or other pneumatic components fitted with rubber components are not suitable.
High-resolution, fused silica or equivalent capillary columns that provide adequate separation of sample components to permit identification and quantitation of target compounds must be used.
100-percent methyl silicone or 5-percent phenyl, 95-percent methyl silicone fused silica capillary columns of 0.25- to 0.32-mm i.d. of varying lengths and with varying thicknesses of stationary phase have been used successfully for non-polar and moderately polar compounds. However, given the diversity of potential target lists, GC column choice is left to the operator, subject to the performance criteria of this method.
Linear quadrupole, magnetic sector, ion trap or time-of-flight mass spectrometers may be used provided they meet specified performance criteria. The mass detector must be capable of collecting data from 35 to 300 atomic mass units (amu) every 1 second or less, utilizing 70 volts (nominal) electron energy in the electron ionization mode, and producing a mass spectrum that meets all the instrument performance acceptance criteria in Section 9 when 50 ηg or less of p-bromofluorobenzene is analyzed.
7.1.1 Use commercially packed tubes meeting the requirements of this method or prepare tubes in the laboratory using sieved sorbents of particle size in the range 20 to 80 mesh that meet the retention and quality control requirements of this method.
7.1.2 This passive air monitoring method can be used without the evaluation specified in Addendum A if the type of tubes described in Section 6.1 are packed with 4-6 cm (typically 400-650 mg) of the sorbents listed in Table 12.1 and used for the respective target analytes.
Although Carbopack
7.1.3 If standard passive sampling tubes are packed with other sorbents or used for analytes other than those tabulated in Section 12.0, method performance and relevant uptake rates should be verified according to Addendum A to this method or by following the techniques described in one of the following national/international standard methods: ISO 16017-2:2003(E), ASTM D6196-03 (Reapproved 2009), or BS EN 14662-4:2005 (all incorporated by reference—see § 63.14)—or reported in the peer-reviewed open literature. A summary table and the supporting evaluation data demonstrating the selected sorbent meets the requirements in Addendum A to this method must be submitted to the regulatory authority as part of a request to use an alternative sorbent.
7.1.4 Passive (diffusive) sampling and thermal desorption methods that have been evaluated at relatively high atmospheric concentrations (
7.1.5 Suitable sorbents for passive sampling must have breakthrough volumes of at least 20 L (preferably >100 L) for the compounds of interest and must quantitatively release the analytes during desorption without exceeding maximum temperatures for the sorbent or instrumentation.
7.1.6 Repack/replace the sorbent tubes or demonstrate tube performance following the requirements in Addendum A to this method at least every 2 years or every 50 uses, whichever occurs first.
7.2.1 Static or dynamic standard atmospheres may be used to prepare calibration tubes and/or to validate passive sampling uptake rates and can be generated from pure chemicals or by diluting concentrated gas standards. The standard atmosphere must be stable at ambient pressure and accurate to ±10 percent of the target gas concentration. It must be possible to maintain standard atmosphere concentrations at the same or lower levels than the target compound concentration objectives of the test. Test atmospheres used for validation of uptake rates must also contain at least 35 percent relative humidity.
Accurate, low-(ppb-) level gas-phase VOC standards are difficult to generate from pure materials and may be unstable depending on analyte polarity and volatility. Parallel monitoring of vapor concentrations with alternative methods, such as pumped sorbent tubes or sensitive/selective on-line detectors, may be necessary to minimize uncertainty. For these reasons, standard atmospheres are rarely used for routine calibration.
7.2.2 Concentrated, pressurized gas phase standards. Accurate (±5 percent or better), concentrated gas phase standards supplied in pressurized cylinders may also be used for calibration. The concentration of the standard should be such that a 0.5-5.0 mL volume contains approximately the same mass of analytes as will be collected from a typical air sample.
7.2.3 Follow manufacturer's guidelines concerning storage conditions and recertification of the concentrated gas phase standard. Gas standards must be recertified a minimum of once every 12 months.
Target analytes can also be introduced to the sampling end of sorbent tubes in the form of liquid calibration standards.
7.3.1 The concentration of liquid standards must be such that an injection of 0.5-2 µl of the solution introduces the same mass of target analyte that is expected to be collected during the passive air sampling period.
7.3.2 Solvent Selection. The solvent selected for the liquid standard must be pure (contaminants <10 percent of minimum analyte levels) and must not interfere chromatographically with the compounds of interest.
7.3.3 If liquid standards are sourced commercially, follow manufacturer's guidelines concerning storage conditions and shelf life of unopened and opened liquid stock standards.
Commercial VOC standards are typically supplied in volatile or non-interfering solvents such as methanol.
7.3.4 Working standards must be stored at 6 °C or less and used or discarded within two weeks of preparation.
7.4.1 Gas-phase deuterated or fluorinated organic compounds may be used as internal standards for MS-based systems.
7.4.2 Typical compounds include deuterated toluene, perfluorobenzene and perfluorotoluene.
7.4.3 Use multiple internal standards to cover the volatility range of the target analytes.
7.4.4 Gas-phase standards must be obtained in pressurized cylinders and containing vendor certified gas concentrations accurate to ±5 percent. The concentration should be such that the mass of internal standard components introduced is similar to those of the target analytes collected during field monitoring.
Certified, preloaded standard tubes, accurate within ±5 percent for each analyte at the microgram level and ±10 percent at the nanogram level, are available commercially
Proficiency testing schemes are also available for TD/GC/MS analysis of sorbent tubes preloaded with common analytes such as benzene, toluene, and xylene.
Use inert, 99.999-percent or higher purity helium as carrier gas. Oxygen and organic filters must be installed in the carrier gas lines supplying the analytical system according to the manufacturer's instructions. Keep records of filter and oxygen scrubber replacement.
8.1.1 Sampling tubes must be conditioned using the apparatus described in Section 6.2.
8.1.2 New tubes should be conditioned for 2 hours to supplement the vendor's conditioning procedure. Recommended temperatures for tube conditioning are given in Table 8.1.
8.1.3 After conditioning, the blank must be verified on each new sorbent tube and on 10 percent of each batch of reconditioned tubes. See Section 9.0 for acceptance criteria.
8.2.1 Conditioned tubes must be sealed using long-term storage caps (see Section 6.4) pushed fully down onto both ends of the PS sorbent tube, tightened by hand and then tighten an additional quarter turn using an appropriate tool.
8.2.2 The capped tubes must be kept in appropriate containers for storage and transportation (see Section 6.4.2). Containers of sorbent tubes may be stored and shipped at ambient temperature and must be kept in a clean environment.
8.2.3 You must keep batches of capped tubes in their shipping boxes or wrap them in uncoated aluminum foil before placing them in their storage container, especially before air freight, because the packaging helps hold caps in position if the tubes get very cold.
8.3.1 Follow guidance given in Method 325A to determine the number of tubes required for site monitoring.
8.3.2 The following additional samples will also be required: Laboratory blanks as specified in Section 9.1.2 (one per analytical sequence minimum), field blanks as specified in Section 9.3.2 (two per sampling period minimum), CCV tubes as specified in Section 10.9.4. (at least one per analysis sequence or every 24 hours), and duplicate samples as specified in Section 9.4 (at least one duplicate sample is required for every 10 sampling locations during each monitoring period).
8.4.1 Allow the tubes to equilibrate with ambient temperature (approximately 30 minutes to 1 hour) at the monitoring location before removing them from their storage/shipping container for sample collection.
8.4.2 Tubes must be used for sampling within 30 days of conditioning (Reference 4).
8.4.3 During field monitoring, the long-term storage cap at the sampling end of the tube is replaced with a diffusion cap and the whole assembly is arranged vertically, with the sampling end pointing downward, under a protective hood or shield—See Section 6.1 of Method 325A for more details.
8.5.1 After sampling, tubes must be immediately resealed with long-term storage caps and placed back inside the type of storage container described in Section 6.4.2.
8.5.2 Exposed tubes may not be placed in the same container as clean tubes. They should not be taken back out of the container until ready for analysis and after they have had time to equilibrate with ambient temperature in the laboratory.
8.5.3 Sampled tubes must be inspected before analysis to identify problems such as loose or missing caps, damaged tubes, tubes that appear to be leaking sorbent or container contamination. Any and all such problems must be documented together with the unique identification number of the tube or tubes concerned. Affected tubes must not be analyzed but must be set aside.
8.5.4 Intact tubes must be analyzed within 30 days of the end of sample collection (within one week for limonene, carene, bis-chloromethyl ether, labile sulfur or nitrogen-containing compounds, and other reactive VOCs).
Ensure ambient temperatures stay below 23 °C during transportation and storage. Refrigeration is not normally required unless the samples contain reactive compounds or cannot be analyzed within 30 days. If refrigeration is used, the atmosphere inside the refrigerator must be clean and free of organic solvents.
The analytical system must be demonstrated to be contaminant free by performing a blank analysis at the beginning of each analytical sequence to demonstrate that the secondary trap and TD/GC/MS analytical equipment are free of any significant interferents.
9.1.1 Laboratory blank tubes must be prepared from tubes that are identical to those used for field sampling.
9.1.2 Analysis of at least one laboratory blank is required per analytical sequence. The laboratory blank must be stored in the laboratory under clean, controlled ambient temperature conditions.
9.1.3 Laboratory blank/artifact levels must meet the requirements of Section 9.2.2 (see also Table 17.1). If the laboratory blank does not meet requirements, stop and perform corrective actions and then re-analyze laboratory blank to ensure it meets requirements.
9.2.1 Conditioned tubes must be demonstrated to be free of contaminants and interference by running 10 percent of the blank tubes selected at random from each conditioned batch under standard sample analysis conditions (see Section 8.1).
9.2.2 Confirm that artifacts and background contamination are ≤ 0.2 ppbv or less than three times the detection limit of the procedure or less than 10 percent of the target compound(s) mass that would be collected if airborne concentrations were at the regulated limit value, whichever is larger. Only tubes that meet these criteria can be
9.2.3 If unacceptable levels of VOCs are observed in the tube blanks, then the processes of tube conditioning and checking the blanks must be repeated.
9.3.1 Field blank tubes must be prepared from tubes that are identical to those used for field sampling—
9.3.2 Field blanks must be shipped to the monitoring site with the sampling tubes and must be stored at the sampling location throughout the monitoring exercise. The field blanks must be installed under a protective hood/cover at the sampling location, but the long-term storage caps must remain in place throughout the monitoring period (see Method 325A). The field blanks are then shipped back to the laboratory in the same container as the sampled tubes. One field blank tube is required for every 10 sampled tubes on a monitoring exercise and no less than two field blanks should be collected, regardless of the size of the monitoring study.
9.3.3 Field blanks must contain no greater than one-third of the measured target analyte or compliance limit for field samples (see Table 17.1). If either field blank fails, flag all data that do not meet this criterion with a note that the associated results are estimated and likely to be biased high due to field blank background.
Duplicate (co-located) samples collected must be analyzed and reported as part of method quality control. They are used to evaluate sampling and analysis precision. Relevant performance criteria are given in Section 9.9.
Unless otherwise noted, monitoring method performance specifications must be demonstrated for the target compounds using the procedures described in Addendum A to this method and the statistical approach presented in Method 301.
Determine the method detection limit under the analytical conditions selected (see Section 11.3) using the procedure in Section 15 of Method 301. The method detection limit is defined for each system by making seven replicate measurements of a concentration of the compound of interest within a factor of five of the detection limit. Compute the standard deviation for the seven replicate concentrations, and multiply this value by three. The results should demonstrate that the method is able to detect analytes such as benzene at concentrations as low as 50 ppt or 1/3rd (preferably 1/10th) of the lowest concentration of interest, whichever is larger.
Determining the detection limit may be an iterative process as described in 40 CFR part 136, Appendix B.
Analytical bias must be demonstrated to be within ±30 percent using Equation 9.1. Analytical bias must be demonstrated during initial setup of this method and as part of the CCV carried out with every sequence of 10 samples or less (see Section 9.14). Calibration standard tubes (see Section 10.0) may be used for this purpose.
Demonstrate an analytical precision within ±20 percent using Equation 9.2. Analytical precision must be demonstrated during initial setup of this method and at least once per year. Calibration standard tubes may be used (see Section 10.0) and data from CCV may also be applied for this purpose.
Use Equation 9.3 to determine and report replicate precision for duplicate field samples (see Section 9.4). The level of agreement between duplicate field samples is a measure of the precision achievable for the entire sampling and analysis procedure. Flag data sets for which the duplicate samples do not agree within 30 percent.
The efficiency of the thermal desorption method must be determined.
9.10.1 Quantitative (>95 percent) compound recovery must be demonstrated by repeat analyses on a same standard tube.
9.10.2 Compound recovery through the TD system can also be demonstrated by comparing the calibration check sample response factor obtained from direct GC injection of liquid standards with that obtained from thermal desorption analysis response factor using the same column under identical conditions.
9.10.3 If the relative response factors obtained for one or more target compounds introduced to the column via thermal desorption fail to meet the criteria in Section 9.10.1, you must adjust the TD parameters to meet the criteria and repeat the experiment. Once the thermal desorption conditions have been optimized, you must repeat this test each time the analytical system is recalibrated to demonstrate continued method performance.
Certified reference standard samples must be used to audit this procedure (if available). Accuracy within 30 percent must be
Tune the mass spectrometer (if used) according to manufacturer's specifications. Verify the instrument performance by analyzing a 50 ηg injection of bromofluorobenzene. Prior to the beginning of each analytical sequence or every 24 hours during continuous GC/MS operation for this method demonstrate that the bromofluorobenzene tuning performance criteria in Table 9.1 have been met.
Run CCV before each sequence of analyses and after every tenth sample to ensure that the previous multi-level calibration (see Section 10.6.3) is still valid.
9.13.1 The sample concentration used for the CCV should be near the mid-point of the multi-level calibration range.
9.13.2 Quantitation software must be updated with response factors determined from the CCV standard. The percent deviation between the initial calibration and the CCV for all compounds must be within 30 percent.
Run another CCV after running each sequence of samples. The initial CCV for a subsequent set of samples may be used as the final CCV for a previous analytical sequence, provided the same analytical method is used and the subsequent set of samples is analyzed immediately (within 4 hours) after the last CCV.
Use a calibration check standard from a second, separate source to verify the original calibration at least once every three months.
Document the procedure used for integration of analytical data including field samples, calibration standards and blanks.
Maintain all QC reports/records for each TD/GC/MS analytical system used for application of this method. Routine quality control requirements for this method are listed below and summarized in Table 17.1.
10.1 Calibrate the analytical system using standards covering the range of analyte masses expected from field samples.
10.2 Analytical results for field samples must fall within the calibrated range of the analytical system to be valid.
10.3 Calibration standard preparation must be fully traceable to primary standards of mass and/or volume, and/or be confirmed using an independent certified reference method.
10.3.1 Preparation of calibration standard tubes from standard atmospheres.
10.3.1.1 Subject to the requirements in Section 7.2.1, low-level standard atmospheres may be introduced to clean, conditioned sorbent tubes in order to produce calibration standards.
10.3.1.2 The standard atmosphere generator or system must be capable of producing sufficient flow at a constant rate to allow the required analyte mass to be introduced within a reasonable time frame and without affecting the concentration of the standard atmosphere itself.
10.3.1.3 The sampling manifold may be heated to minimize risk of condensation but the temperature of the gas delivered to the sorbent tubes may not exceed 100 °F.
10.3.1.4 The flow rates passed through the tube should be in the order of 50-100 mL/min and the volume of standard atmosphere sampled from the manifold or chamber must not exceed the breakthrough volume of the sorbent at the given temperature.
10.4 Preparation of calibration standard tubes from concentrated gas standards.
10.4.1 If a suitable concentrated gas standard (see Section 7.2.2) can be obtained, follow the manufacturer's recommendations relating to suitable storage conditions and product lifetime.
10.4.2 Introduce precise 0.5 to 500.0 mL aliquots of the standard to the sampling end of conditioned sorbent tubes in a 50-100 mL/min flow of pure carrier gas.
This can be achieved by connecting the sampling end of the tube to an unheated GC injector (see Section 6.6) and introducing the aliquot of gas using a suitable gas syringe. Gas sample valves could alternatively be used to meter the standard gas volume.
10.4.3 Each sorbent tube should be left connected to the flow of gas for 2 minutes after standard introduction. As soon as each spiked tube is removed from the injection unit, seal it with long-term storage caps and place it in an appropriate tube storage/transportation container if it is not to be analyzed within 24 hours.
10.5 Preparation of calibration standard tubes from liquid standards.
10.5.1 Suitable standards are described in Section 7.3.
10.5.2 Introduce precise 0.5 to 2 µl aliquots of liquid standards to the sampling end of sorbent tubes in a flow (50-100 mL/min) of carrier gas using a precision syringe and an unheated injector (Section 6.5). The flow of gas should be sufficient to completely vaporize the liquid standard.
If the analytes of interest are higher boiling than n-decane, reproducible analyte transfer to the sorbent bed is optimized by allowing the tip of the syringe to gently touch the sorbent retaining gauze at the sampling end of the tube.
10.5.3 Each sorbent tube is left connected to the flow of gas for 5 minutes after liquid standard introduction.
10.5.3.1 As soon as each spiked tube is removed from the injection unit, seal it with long-term storage caps and place it in an appropriate tube storage container if it is not to be analyzed within 24 hours.
In cases where it is possible to selectively purge the solvent from the tube while all target analytes are quantitatively retained, a larger 2 µL injection may be made for optimum accuracy. However, if the solvent cannot be selectively purged and will be present during analysis, the injection volume should be as small as possible (
This standard preparation technique requires the entire liquid plug including the tip volume be brought into the syringe barrel. The volume in the barrel is recorded, the syringe is inserted into the septum of the spiking apparatus. The liquid is then quickly injected. Any remaining liquid in the syringe tip is brought back into the syringe barrel. The volume in the barrel is recorded and the amount spiked onto the tube is the difference between the before spiking volume and the after spiking volume. A bias occurs with this method when sample is drawn continuously up into the syringe to the specified volume
10.6 Preparation of calibration standard tubes from multiple standards.
10.6.1 If it is not possible to prepare one standard containing all the compounds of interest (
10.6.2 Follow the procedures described in Sections 10.4 and 10.5, respectively, for introducing each gas and/or liquid standard to the tube and load those containing the highest boiling compounds of interest first and the lightest species last.
10.7 Additional requirements for preparation of calibration tubes.
10.7.1 Storage of Calibration Standard Tubes
10.7.1.1 Seal tubes with long-term storage caps immediately after they have been disconnected from the standard loading manifold or injection apparatus.
10.7.1.2 Calibration standard tubes may be stored for no longer than 30 days and should be refrigerated if there is any risk of chemical interaction or degradation. Audit standards (see section 9.11) are exempt from this criteria and may be stored for the shelf-life specified on their certificates.
10.8 Keep records for calibration standard tubes to include the following:
10.8.1 The stock number of any commercial liquid or gas standards used.
10.8.2 A chromatogram of the most recent blank for each tube used as a calibration standard together with the associated analytical conditions and date of cleaning.
10.8.3 Date of standard loading.
10.8.4 List of standard components, approximate masses and associated confidence levels.
10.8.5 Example analysis of an identical standard with associated analytical conditions.
10.8.6 A brief description of the method used for standard preparation.
10.8.7 The standard's expiration date.
10.9 TD/GC/MS using standard tubes to calibrate system response.
10.9.1 Verify that the TD/GC/MS analytical system meets the instrument performance criteria given in Section 9.1.
10.9.2 The prepared calibration standard tubes must be analyzed using the analytical conditions applied to field samples (see Section 11.0) and must be selected to ensure quantitative transfer and adequate chromatographic resolution of target compounds, surrogates, and internal standards in order to enable reliable identification and quantitation of compounds of interest. The analytical conditions should also be sufficiently stringent to prevent buildup of higher boiling, non-target contaminants that may be collected on the tubes during field monitoring.
10.9.3 Calibration range. Each TD/GC/MS system must be calibrated at five concentrations that span the monitoring range of interest before being used for sample analysis. This initial multi-level calibration determines instrument sensitivity under the analytical conditions selected and the linearity of GC/MS response for the target compounds. One of the calibration points must be within a factor of five of the detection limit for the compounds of interest.
10.9.4 One of the calibration points from the initial calibration curve must be at the same concentration as the daily CCV standard (
10.9.5 Calibration frequency. Each GC/MS system must be recalibrated with a full 5-point calibration curve following corrective action (
10.9.5.1 CCV checks must be carried out on a regular routine basis as described in Section 9.14.
10.9.5.2 Quantitation ions for the target compounds are shown in Table 10.1. Use the primary ion unless interferences are present, in which case you should use a secondary ion.
11.1.1 Each sequence of analyses must be ordered as follows:
11.1.1.1 CCV.
11.1.1.2 A laboratory blank.
11.1.1.3 Field blank.
11.1.1.4 Sample(s).
11.1.1.5 Field blank.
11.1.1.6 CCV after 10 field samples.
11.1.1.7 CCV at the end of the sample batch.
11.2.1 Ensure all sample tubes and field blanks are at ambient temperature before removing them from the storage container.
11.2.2 If using an automated TD/GC/MS analyzer, remove the long-term storage caps from the tubes, replace them with appropriate analytical caps, and load them into the system in the sequence described in Section 11.1. Alternatively, if using a manual system, uncap and analyze each tube, one at a time, in the sequence described in Section 11.1.
11.2.3 The following thermal desorption system integrity checks and procedures are required before each tube is analyzed.
Commercial thermal desorbers should implement these steps automatically.
11.2.3.1 Tube leak test: Each tube must be leak tested as soon as it is loaded into the carrier gas flow path before analysis to ensure data integrity.
11.2.3.2 Conduct the leak test at the GC carrier gas pressure, without heat or gas flow applied. Tubes that fail the leak test should not be analyzed, but should be resealed and stored intact. On automated systems, the instrument should continue to leak test and analyze subsequent tubes after a given tube has failed. Automated systems must also store and record which tubes in a sequence have failed the leak test. Information on failed tubes should be downloaded with the batch of sequence information from the analytical system.
11.2.3.3 Leak test the sample flow path. Leak check the sample flow path of the thermal desorber before each analysis without heat or gas flow applied to the sample tube. Stop the automatic sequence of tube desorption and GC analysis if any leak is detected in the main sample flow path. This process may be carried out as a separate step or as part of Section 11.2.3.2.
11.2.4.1 Tubes may be dry purged with a flow of pure dry gas passing into the tube from the sampling end, to remove water vapor and other very volatile interferents if required.
11.2.5.1 Use the internal standard addition function of the automated thermal desorber (if available) to introduce a precise aliquot of the internal standard to the sampling end of each tube after the leak test and shortly before primary (tube) desorption).
This step can be combined with dry purging the tube (Section 11.2.4) if required.
11.2.5.2 If the analyzer does not have a facility for automatic IS addition, gas or liquid internal standard can be manually introduced to the sampling end of tubes in a flow of carrier gas using the types of procedure described in Sections 10.3 and 10.4, respectively.
11.2.6 Pre-purge. Each tube should be purged to vent with carrier gas flowing in the desorption direction (
11.3.1.1 Ensure that the pressure and purity of purge and carrier gases supplying the TD/GC/MS system, meet manufacturer specifications and the requirements of this method.
11.3.1.2 Ensure also that the analytical method selected meets the QC requirements of this method (Section 9) and that all the analytical parameters are at set point.
11.3.1.3 Conduct predesorption system checks (see Section 11.2).
11.3.1.4 Desorb the sorbent tube under conditions demonstrated to achieve >95 percent recovery of target compounds (see Section 9.5.2).
Typical tube desorption conditions range from 280-350 °C for 5-15 minutes with a carrier gas flow of 30-100 mL/min passing through the tube from the non-sampling end such that analytes are flushed out of the tube from the sampling end. Desorbed VOCs are concentrated (refocused) on a secondary, cooled sorbent trap integrated into the analytical equipment (see Figure 17.4). The focusing trap is typically maintained at a temperature between −30 and +30 °C during focusing. Selection of hydrophobic sorbents for focusing and setting a trapping temperature of +25 to 27 °C aid analysis of humid samples because these settings allow selective elimination of any residual water from the system, prior to GC/MS analysis.
The transfer of analytes from the tube to the focusing trap during primary (tube) desorption can be carried out splitless or under controlled split conditions (see Figure 17.4) depending on the masses of target compounds sampled and the requirements of the system—sensitivity, required calibration range, column overload limitations, etc. Instrument controlled sample splits must be demonstrated by showing the reproducibility using calibration standards. Field and laboratory blank samples must be analyzed at the same split as the lowest calibration standard. During secondary (trap) desorption the focusing trap is heated rapidly (typically at rates >40 °C/s) with inert (carrier) gas flowing through the trap (3-100 mL/min) in the reverse direction to that used during focusing.
11.3.1.5 The split conditions selected for optimum field sample analysis must also be demonstrated on representative standards.
Typical trap desorption temperatures are in the range 250-360 °C, with a “hold” time of 1-3 minutes at the highest temperature. Trap desorption automatically triggers the start of GC analysis. The trap desorption can also be carried out under splitless conditions (
11.3.1.6 Analyzed tubes must be resealed with long-term storage caps immediately after analysis (manual systems) or after completion of a sequence (automated systems). This prevents contamination, minimizing the extent of tube reconditioning required before subsequent reuse.
11.3.2.1 Heat/cool the GC oven to its starting set point.
11.3.2.2 If using a GC/MS system, it can be operated in either MS-Scan or MS-SIM mode (depending on required sensitivity levels and the type of mass spectrometer selected). As soon as trap desorption and transfer of analytes into the GC column triggers the start of the GC/MS analysis, collect mass spectral data over a range of masses from 35 to 300 amu. Collect at least 10 data points per eluting chromatographic peak in order to adequately integrate and quantify target compounds.
11.3.2.3 Use secondary ion quantitation only when there are sample matrix interferences with the primary ion. If secondary ion quantitation is performed, flag the data and document the reasons for the alternative quantitation procedure.
11.3.2.4 Data reduction is performed by the instruments post processing program that is automatically accessed after data acquisition is completed at the end of the GC run. The concentration of each target compound is calculated using the previously established response factors for the CCV analyzed in Section 11.1.1.6.
11.3.2.5 Whenever the thermal desorption—GC/MS analytical method is changed or major equipment maintenance is performed, you must conduct a new five-level calibration (see Section 10.6.3). System calibration remains valid as long as results from subsequent CCV are within 30 percent of the most recent 5-point calibration (see Section 10.9.5). Include relevant CCV data in the supporting information in the data report for each set of samples.
11.3.2.6 Document, flag and explain all sample results that exceed the calibration range. Report flags and provide documentation in the analytical results for the affected sample(s).
12.1.1 Label sample tubes with a unique identification number as described in Section 6.3.
12.1.2 Keep records of the tube numbers and sorbent lots used for each sampling period.
12.1.3 Keep records of sorbent tube packing if tubes are manually prepared in the
12.1.4 Keep records of the conditioning and blanking of tubes. These records must include, but are not limited to, the unique identification number and measured background resulting from the tube conditioning.
12.1.5 Record the location, dates, tube identification and times associated with each sample collection. Record this information on a Chain of Custody form that is sent to the analytical laboratory.
12.1.6 Field sampling personnel must complete and send a Chain of Custody to the analysis laboratory (see Section 8.6.4 of Method 325A for what information to include and Section 17.0 of this method for an example form). Duplicate copies of the Chain of Custody must be included with the sample report and stored with the field test data archive.
12.1.7 Field sampling personnel must also keep records of the unit vector wind direction, sigma theta, temperature and barometric pressure averages for the sampling period. See Section 8.3.4 of Method 325A.
12.1.8 Laboratory personnel must record the sample receipt date, and analysis date.
12.1.9 Laboratory personnel must maintain records of the analytical method and sample results in electronic or hardcopy in sufficient detail to reconstruct the calibration, sample, and quality control results from each sampling period.
12.2.1 Complete the calculations in this section to determine compliance with calibration quality control criteria (see also Table 17.1).
12.2.1.1 Response factor (RF). Calculate the RF using Equation 12.1:
12.2.1.2 Standard deviation of the response factors (SD
12.2.1.3 Percent deviation (%DEV). Calculate the %DEV using Equation 12.3:
12.2.1.4 Relative percent difference (RPD). Calculate the RPD using Equation 12.4:
12.2.2 Determine the equivalent concentration of compounds in atmospheres as follows.
12.2.3 Correct target concentrations determined at the sampling site temperature and atmospheric pressure to standard conditions (25 °C and 760 mm mercury) using Equation 12.5 (Reference 21).
12.2.4 For passive sorbent tube samples, calculate the concentration of the target compound(s) in the sampled air, in μg/m
Diffusive uptake rates for common VOCs, using carbon sorbents packed into sorbent tubes of the dimensions specified in Section 6.1, are listed in Table 12.1. Adjust analytical conditions to keep expected sampled masses within range (see Sections 11.3.1.3 to 11.3.1.5). Best possible method detection limits are typically in the order of 0.1 ppb for 1,3-butadiene and 0.05 ppb for volatile aromatics such as benzene for 14-day monitoring. However, actual detection limits will depend upon the analytical conditions selected.
The performance of this procedure for VOC not listed in Table 12.1 is determined using the procedure in Addendum A of this Method or by one of the following national/international standard methods: ISO 16017-2:2003(E), ASTM D6196-03 (Reapproved 2009), or BS EN 14662-4:2005 (all incorporated by reference—see § 63.14).
13.1 The valid range for measurement of VOC is approximately 0.5 µg/m
13.2 Diffusive sorbent tubes compatible with passive sampling and thermal desorption methods have been evaluated at relatively high atmospheric concentrations (
13.3 Best possible detection limits and maximum quantifiable concentrations of air pollutants range from sub-part-per-trillion (sub-ppt) for halogenated species such as CCl4 and the freons using an electron capture detector (ECD), SIM Mode GC/MS, triple quad MS or GC/TOF MS to sub-ppb for volatile hydrocarbons collected over 72 hours followed by analysis using GC with quadrupole MS operated in the full SCAN mode.
13.3.1 Actual detection limits for atmospheric monitoring vary depending on several key factors. These factors are:
• Minimum artifact levels.
• GC detector selection.
• Time of exposure for passive sorbent tubes.
• Selected analytical conditions, particularly column resolution and split ratio.
This method involves the use of ambient concentrations of gaseous compounds that post little or no danger of pollution to the environment.
Dispose of expired calibration solutions as hazardous materials. Exercise standard laboratory environmental practices to minimize the use and disposal of laboratory solvents.
ADDENDUM A to Method 325B—Method 325 Performance Evaluation
A.1.1 To be measured by Methods 325A and 325B, each new target volatile organic compound (VOC) or sorbent that is not listed in Table 12.1 must be evaluated by exposing the selected sorbent tube to a known concentration of the target compound(s) in an exposure chamber following the procedure in this Addendum or by following the procedures in the national/international standard methods: ISO 16017-2:2003(E),
A.1.2 You must determine the uptake rate and the relative standard deviation compared to the theoretical concentration of volatile material in the exposure chamber for each of the tests required in this method. If data that meet the requirement of this Addendum are available in the peer reviewed open literature for VOCs of interest collected on your passive sorbent tube configuration, then such data may be submitted in lieu of the testing required in this Addendum.
A.1.3 You must expose sorbent tubes in a test chamber to parts per trillion by volume (pptv) and low parts per billion by volume (ppbv) concentrations of VOCs in humid atmospheres to determine the sorbent tube uptake rate and to confirm compound capture and recovery.
The technique described here is one approach for determining uptake rates for new sorbent/sorbate pairs. It is equally valid to follow the techniques described in any one of the following national/international standards methods: ISO 16017-2:2003(E), ASTM D6196-03 (Reapproved 2009), or BS EN 14662-4:2005 (all incorporated by reference—see § 63.14).
A.2.1 Known concentrations of VOC are metered into an exposure chamber containing sorbent tubes filled with media selected to capture the volatile organic compounds of interest (see Figure A.1 and A.2 for an example of the exposure chamber and sorbent tube retaining rack). VOC are diluted with humid air and the chamber is allowed to equilibrate for 6 hours. Clean passive sampling devices are placed into the chamber and exposed for a measured period of time. The passive uptake rate of the passive sampling devices is determined using the standard and dilution gas flow rates. Chamber concentrations are confirmed with whole gas sample collection and analysis or direct interface volatile organic compound measurement methods.
A.2.2 An exposure chamber and known gas concentrations must be used to challenge and evaluate the collection and recovery of target compounds from the sorbent and tube selected to perform passive measurements of VOC in atmospheres.
A.3.1
A.3.2
A.3.3
A.3.4
A.3.5
A.3.6
A.3.7
A.3.8
A.3.9
A.3.10
A.3.11
A.3.12
A.3.13
A.4.1 VOC contaminants in water can contribute interference or bias results high. Use only distilled, organic-free water for dilution gas humidification.
A.4.2 Solvents and other VOC-containing liquids can contaminate the exposure chamber. Store and use solvents and other VOC-containing liquids in the exhaust hood when exposure experiments are in progress to prevent the possibility of contamination of VOCs into the chamber through the chamber's exhaust vent.
Whenever possible, passive sorbent evaluation should be performed in a VOC free laboratory.
A.4.3 PSDs should be handled by personnel wearing only clean, white cotton or powder free nitrile gloves to prevent contamination of the PSDs with oils from the hands.
A.4.4 This performance evaluation procedure is applicable to only volatile materials that can be measured accurately with direct interface gas chromatography or whole gas sample collection, concentration and analysis. Alternative methods to confirm the concentration of volatile materials in exposure chambers are subject to Administrator approval.
A.5.1 This procedure does not address all of the safety concerns associated with its use. It is the responsibility of the user of this standard to establish appropriate field and laboratory safety and health practices and determine the applicability of regulatory limitations prior to use.
A.5.2 Laboratory analysts must exercise appropriate care in working with high-pressure gas cylinders.
A.6.1 You must use an exposure chamber of sufficient size to simultaneously expose a minimum of eight sorbent tubes.
A.6.2 Your exposure chamber must not contain VOC that interfere with the compound under evaluation. Chambers made of glass and/or stainless steel have been used successfully for measurement of known concentration of selected VOC compounds.
A.6.3 The following equipment and supplies are needed:
• Clean, white cotton or nitrile gloves;
• Conditioned passive sampling device tubes and diffusion caps; and
• NIST traceable high resolution digital gas mass flow meters (MFMs) or flow controllers (MFCs).
A.7.1 You must generate an exposure gas that contains between 35 and 75 percent relative humidity and a concentration of target compound(s) within 2 to 5 times the concentration to be measured in the field.
A.7.2 Target gas concentrations must be generated with certified gas standards and diluted with humid clean air. Dilution to reach the desired concentration must be done with zero grade air or better.
A.7.3 The following reagents and standards are needed:
• Distilled water for the humidification;
• VOC standards mixtures in high-pressure cylinder certified by the supplier (
• Purified dilution air containing less than 0.2 ppbv of the target VOC.
A.8.1 You must use certified gas standards diluted with humid air. Generate humidified air by adding distilled organic free water to purified or zero grade air. Humidification may be accomplished by quantitative addition of water to the air dilution gas stream in a heated chamber or by passing purified air through a humidifying bubbler. You must control the relative humidity in the test gas throughout the period of passive sampler exposure.
The RH in the exposure chamber is directly proportional to the fraction of the purified air that passes through the water in the bubbler before entering the exposure chamber. Achieving uniform humidification in the proper range is a trial-and-error process with a humidifying bubbler. You may need to heat the bubbler to achieve sufficient humidity. An equilibration period of approximately 15 minutes is required following each adjustment of the air flow through the humidifier. Several adjustments or equilibration cycles may be required to achieve the desired RH level.
You will need to determine both the dilution rate and the humidification rate for your design of the exposure chamber by trial and error before performing method evaluation tests.
A.8.2 Prepare and condition sorbent tubes following the procedures in Method 325B Section 7.0.
A.8.3 You must verify that the exposure chamber does not leak.
A.8.4 You must complete two evaluation tests using a minimum of eight passive sampling tubes in each test with less than 5-percent depletion of test analyte by the samplers.
A.8.4.1 Perform at least one evaluation at two to five times the estimated analytical detection limit or less.
A.8.4.2 Perform second evaluation at a concentration equivalent to the middle of the analysis calibration range.
A.8.5 You must evaluate the samplers in the test chamber operating between 35 percent and 75 percent RH, and at 25 ± 5 °C. Allow the exposure chamber to equilibrate for 6 hours before starting an evaluation.
A.8.6 The flow rate through the chamber must be ≤0.5 meter per second face velocity across the sampler face.
A.8.7 Place clean, ready to use sorbent tubes into the exposure chamber for predetermined amounts of time to evaluate collection and recovery from the tubes. The exposure time depends on the concentration of volatile test material in the chamber and the detection limit required for the sorbent tube sampling application. Exposure time
A.8.7.1 To start the exposure, place the clean PSDs equipped with diffusion caps on the tube inlet into a retaining rack.
A.8.7.2 Place the entire retaining rack inside the exposure chamber with the diffusive sampling end of the tubes facing into the chamber flow. Seal the chamber and record the exposure start time, chamber RH, chamber temperature, PSD types and numbers, orientation of PSDs, and volatile material mixture composition (see Figure A.2).
A.8.7.3 Diluted, humidified target gas must be continuously fed into the exposure chamber during cartridge exposure. Measure the flow rate of target compound standard gas and dilution air to an accuracy of 5 percent.
A.8.7.4 Record the time, temperature, and RH at the beginning, middle, and end of the exposure time.
A.8.7.5 At the end of the exposure time, remove the PSDs from the exposure chamber. Record the exposure end time, chamber RH, and temperature.
A.9.1 Monitor and record the exposure chamber temperature and RH during PSD exposures.
A.9.2 Measure the flow rates of standards and purified humified air immediately following PSD exposures.
A.10.1 Follow the procedures described in Method 325B Section 10.0 for calibration.
A.10.2 Verify chamber concentration by direct injection into a gas chromatograph calibrated for the target compound(s) or by collection of an integrated SUMMA canister followed by analysis using a preconcentration gas chromatographic method such as EPA Compendium Method TO-15, Determination of VOCs in Air Collected in Specially-Prepared Canisters and Analyzed By GC/MS.
A.10.2.1 To use direct injection gas chromatography to verify the exposure chamber concentration, follow the procedures in Method 18 of 40 CFR part 60, Appendix A-6. The method ASTM D6420-99 (Reapproved 2010) (incorporated by reference—see § 63.14) is an acceptable alternative to EPA Method 18 of 40 CFR part 60).
Direct injection gas chromatography may not be sufficiently sensitive for all compounds. Therefore, the whole gas preconcentration sample and analysis method may be required to measure at low concentrations.
A.10.2.2 To verify exposure chamber concentrations using SUMMA canisters,
A.10.2.3 Compare the theoretical concentration of volatile material added to the test chamber to the measured concentration to confirm the chamber operation. Theoretical concentration must agree with the measured concentration within 30 percent.
Analyze the sorbent tubes following the procedures described in Section 11.0 of Method 325B.
Keep records for the sorbent tube evaluation to include at a minimum the following information:
A.12.1 Sorbent tube description and specifications.
A.12.2 Sorbent material description and specifications.
A.12.3 Volatile analytes used in the sampler test.
A.12.4 Chamber conditions including flow rate, temperature, and relative humidity.
A.12.5 Relative standard deviation of the sampler results at the conditions tested.
A.12.6 95 percent confidence limit on the sampler overall accuracy.
A.12.7 The relative accuracy of the sorbent tube results compared to the direct chamber measurement by direct gas chromatography or SUMMA canister analysis.
A.13.1 Sorbent tube performance is acceptable if the relative accuracy of the passive sorbent sampler agrees with the active measurement method by ±10 percent at the 95 percent confidence limit and the uptake ratio is equal to greater than 0.5 mL/min (1 ng/ppm-min).
For example, there is a maximum deviation comparing Perkin-Elmer passive type sorbent tubes packed with Carbopack
A13.2 Data Analysis and Calculations for Method Evaluation
A.13.2.1 Calculate the theoretical concentration of VOC standards using Equation A.1.
A.13.2.3 Determine the uptake rate of the target gas being evaluated using Equation A.2.
A.13.2.4 Estimate the variance (relative standard deviation (RSD)) of the inter-sampler results at each condition tested using Equation A.3. RSD for the sampler is estimated by pooling the variance estimates from each test run.
A.13.2.4 Determine the percent relative standard deviation of the inter-sampler results using Equation A.4.
A.13.2.5 Determine the 95 percent confidence interval for the sampler results using Equation A.5. The confidence interval is determined based on the number of test runs performed to evaluate the sorbent tube and sorbent combination. For the minimum test requirement of eight samplers tested at two concentrations, the number of tests is 16 and the degrees of freedom are 15.
A.13.2.6 Determine the relative accuracy of the sorbent tube combination compared to the active sampling results using Equation A.6.
This method involves the use of ambient concentrations of gaseous compounds that post little or no pollution to the environment.
Expired calibration solutions should be disposed of as hazardous materials.
1. ISO TC 146/SC 02 N 361 Workplace atmospheres—Protocol for evaluating the performance of diffusive samplers.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; proposed incidental harassment authorization; request for comments.
NMFS has received an application from the Lamont-Doherty Earth Observatory (Lamont-Doherty) in collaboration with the National Science Foundation (NSF), for an Incidental Harassment Authorization (Authorization) to take marine mammals, by harassment only, incidental to conducting a marine geophysical (seismic) survey in the South Atlantic Ocean, January through March 2016. The proposed dates for this action would be early January 2016 through March 31, 2016, to account for minor deviations due to logistics and weather. Per the Marine Mammal Protection Act, we are requesting comments on our proposal to issue an Authorization to Lamont-Doherty to incidentally take, by Level B harassment, 38 species of marine mammals during the specified activity and to incidentally take, by Level A harassment, 16 species of marine mammals. Although considered unlikely, any Level A harassment potentially incurred would be expected to be in the form of some smaller degree of permanent hearing loss due in part to the required monitoring measures for detecting marine mammals and required mitigation measures for power downs or shut downs of the airgun array if any animal is likely to enter the Level A exclusion zone. NMFS does not expect mortality or complete deafness of marine mammals to result from this survey.
NMFS must receive comments and information on or before December 31, 2015.
Address comments on the application to Jolie Harrison, Chief, Permits and Conservation Division, Office of Protected Resources, National Marine Fisheries Service, 1315 East-West Highway, Silver Spring, MD 20910. The mailbox address for providing email comments is
To obtain an electronic copy of Lamont-Doherty's application, NSF's draft environmental analysis, NMFS' draft Environmental Assessment, and a list of the references used in this document, write to the previously mentioned address, telephone the contact listed here (see
Information in Lamont-Doherty's application, NSF's draft environmental analysis, NMFS' draft Environmental Assessment and this notice collectively provide the environmental information related to the proposed issuance of the Authorization for public review and comment.
Jeannine Cody, NMFS, Office of Protected Resources, NMFS (301) 427-8401.
Section 101(a)(5)(D) of the Marine Mammal Protection Act of 1972, as amended (MMPA; 16 U.S.C. 1361
An Authorization shall be granted for the incidental taking of small numbers of marine mammals if NMFS finds that the taking will have a negligible impact on the species or stock(s), and will not have an unmitigable adverse impact on the availability of the species or stock(s) for subsistence uses (where relevant). The Authorization must also set forth the permissible methods of taking; other means of effecting the least practicable adverse impact on the species or stock and its habitat (
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].
On July 29, 2015, NMFS received an application from Lamont-Doherty requesting that NMFS issue an Authorization for the take of marine mammals, incidental to Texas A&M University and the University of Texas conducting a seismic survey in the South Atlantic Ocean, January through March 2016. Following the initial application submission, Lamont-Doherty submitted a revised application with revised take estimates. NMFS considered the revised application adequate and complete on October 30, 2015.
Lamont-Doherty proposes to conduct a two-dimensional (2-D), seismic survey on the R/V
Lamont-Doherty plans to use one source vessel, the
The purpose of the survey is to collect and analyze seismic refraction data from the Mid-Atlantic Ridge westward to the Rio Grande Rise to study the evolution of the South Atlantic Ocean crust on million-year timescales and the evolution and stability of low-spreading ridges over time. NMFS refers the public to Lamont-Doherty's application (see page 3) for more detailed information on the proposed research objectives.
Lamont-Doherty proposes to conduct the seismic survey for approximately 42 days, which includes approximately 22 days of seismic surveying with 10 days of OBS deployment and retrieval. The proposed study (
NMFS refers the reader to the Detailed Description of Activities section later in this notice for more information on the scope of the proposed activities.
Lamont-Doherty proposes to conduct the proposed seismic survey in the South Atlantic Ocean, located approximately between 10-35° W, 27-33° S (see Figure 1). Water depths in the survey area range from approximately 1,150 to 4,800 meters (m) (3,773 feet [ft] to 2.98 miles [mi]).
The proposed survey's principal investigators are Drs. R. Reece and R. Carlson (Texas A&M University) and Dr. G. Christeson (University of Texas at Austin).
The
The survey would involve one source vessel, the R/V
The
The vessel also has an observation tower from which protected species visual observers (observers) would watch for marine mammals before and during the proposed seismic acquisition operations. When stationed on the observation platform, the observer's eye level will be approximately 21.5 m (71 ft) above sea level providing the observer an unobstructed view around the entire vessel.
The proposed survey would cover a total of approximately 3,263 km (2,028 mi) of transect lines. The proposed survey is one continuous transect line with transect lines that cross the main line at six locations.
During the survey, the
The airguns are a mixture of Bolt 1500LL and Bolt 1900LLX airguns ranging in size from 40 to 220 in
During the survey, Lamont-Doherty would plan to use the full array with most of the airguns in inactive mode. The
Airguns function by venting high-pressure air into the water, which creates an air bubble. The pressure signature of an individual airgun consists of a sharp rise and then fall in pressure, followed by several positive and negative pressure excursions caused by the oscillation of the resulting air bubble. The oscillation of the air bubble transmits sounds downward through the seafloor, and there is also a reduction in the amount of sound transmitted in the near horizontal direction. The airgun array also emits sounds that travel horizontally toward non-target areas.
The nominal source levels of the airgun subarrays on the
Multibeam Echosounder: The
The hull-mounted echosounder emits brief pulses of sound (also called a ping) (10.5 to 13.0 kHz) in a fan-shaped beam that extends downward and to the sides of the ship. The transmitting beamwidth is 1 or 2° fore-aft and 150° athwartship and the maximum source level is 242 dB re: 1 μPa.
Each ping consists of eight (in water greater than 1,000 m; 3,280 ft) or four (in water less than 1,000 m; 3,280 ft) successive, fan-shaped transmissions, from two to 15 milliseconds (ms) in duration and each ensonifying a sector that extends 1° fore-aft. Continuous wave pulses increase from 2 to 15 ms long in water depths up to 2,600 m (8,530 ft). The echosounder uses frequency-modulated chirp pulses up to 100-ms long in water greater than 2,600 m (8,530 ft). The successive transmissions span an overall cross-track angular extent of about 150°, with 2-ms gaps between the pulses for successive sectors.
Sub-bottom Profiler: The
The profiler is capable of reaching depths of 10,000 m (6.2 mi). The dominant frequency component is 3.5 kHz and a hull-mounted transducer on the vessel directs the beam downward in a 27° cone. The power output is 10 kilowatts (kW), but the actual maximum radiated power is three kilowatts or 222 dB re: 1 μPa. The ping duration is up to 64 ms with a pulse interval of one second, but a common mode of operation is to broadcast five pulses at 1-s intervals followed by a 5-s pause.
Ocean Bottom Seismometers: The
Lamont-Doherty proposes to use one of two types of OBSs: The Woods Hole Oceanographic Institute (WHOI) or the Scripps Institution of Oceanography (SIO) OBS.
The WHOI D2 OBS is approximately 0.9 m (2.9 ft) high with a maximum diameter of 50 centimeters (cm) (20 inches [in]). An anchor, made of a rolled steel bar grate that measures approximately 2.5 by 30.5 by 38.1 cm (1 by 12 by 15 in) and weighs 23 kilograms (kg) (51 pounds [lbs]) would anchor the seismometer to the seafloor. The SIO L-Cheapo OBS is approximately 0.9 m (2.9 ft) high with a maximum diameter of 97 centimeters (cm) (3.1 ft). The SIO anchors consist of 36-kg (79-lb) iron gates and measure approximately 7 by 91 by 91.5 cm (3 by 36 by 36 inches).
After the
The
Hydrophone Streamer: Lamont-Doherty would deploy the single hydrophone streamer for multichannel operations after concluding the OBS operations. As the
Table 1 in this notice provides the following: All marine mammal species with possible or confirmed occurrence in the proposed activity area; information on those species' regulatory status under the MMPA and the Endangered Species Act of 1973 (16 U.S.C. 1531
NMFS refers the public to Lamont-Doherty's application, NSF's draft environmental analysis (see
This section includes a summary and discussion of the ways that components (
NMFS intends to provide a background of potential effects of Lamont-Doherty's activities in this section. This section does not consider the specific manner in which Lamont-Doherty would carry out the proposed activity, what mitigation measures Lamont-Doherty would implement, and how either of those would shape the anticipated impacts from this specific activity. Operating active acoustic sources, such as airgun arrays, has the potential for adverse effects on marine mammals. The majority of anticipated impacts would be from the use of the airgun array.
When considering the influence of various kinds of sound on the marine environment, it is necessary to understand that different kinds of marine life are sensitive to different frequencies of sound. Current data indicate that not all marine mammal species have equal hearing capabilities (Richardson
Southall
The functional groups applicable to this proposed survey and the associated frequencies are:
• Low frequency cetaceans (13 species of mysticetes): Functional hearing estimates occur between approximately 7 Hertz (Hz) and 25 kHz (extended from 22 kHz based on data indicating that some mysticetes can hear above 22 kHz; Au
• Mid-frequency cetaceans (32 species of dolphins, six species of larger toothed whales, and 19 species of beaked and bottlenose whales): Functional hearing estimates occur between approximately 150 Hz and 160 kHz;
• High-frequency cetaceans (eight species of true porpoises, six species of river dolphins,
• Pinnipeds in water: Phocid (true seals) functional hearing estimates occur between approximately 75 Hz and 100 kHz (Hemila
Approximately 42 marine mammal species (8 mysticetes, 32 odontocetes, and two pinnipeds) would likely occur in the proposed action area. Table 2 presents the classification of these species into their respective functional hearing group. NMFS consider a species' functional hearing group when analyzing the effects of exposure to sound on marine mammals.
The effects of sounds from airgun operations might include one or more of the following: Tolerance, masking of natural sounds, behavioral disturbance, temporary or permanent impairment, or non-auditory physical or physiological effects (Richardson
Studies on marine mammals' tolerance to sound in the natural environment are relatively rare. Richardson
Numerous studies have shown that pulsed sounds from airguns are often readily detectable in the water at distances of many kilometers. Several studies have also shown that marine mammals at distances of more than a few kilometers from operating seismic vessels often show no apparent response. That is often true even in cases when the pulsed sounds must be readily audible to the animals based on measured received levels and the hearing sensitivity of the marine mammal group. Although various baleen whales and toothed whales, and (less frequently) pinnipeds have been shown to react behaviorally to airgun pulses under some conditions, at other times marine mammals of all three types have shown no overt reactions (Stone, 2003; Stone and Tasker, 2006; Moulton
Weir (2008) observed marine mammal responses to seismic pulses from a 24 airgun array firing a total volume of either 5,085 in
Bain and Williams (2006) examined the effects of a large airgun array (maximum total discharge volume of 1,100 in
Pirotta
Marine mammals use acoustic signals for a variety of purposes, which differ among species, but include communication between individuals, navigation, foraging, reproduction, avoiding predators, and learning about their environment (Erbe and Farmer, 2000; Tyack, 2000).
The term masking refers to the inability of an animal to recognize the occurrence of an acoustic stimulus because of interference of another acoustic stimulus (Clark
Introduced underwater sound may, through masking, may more specifically reduce the effective communication distance of a marine mammal species if the frequency of the source is close to that used as a signal by the marine mammal, and if the anthropogenic sound is present for a significant fraction of the time (Richardson
Marine mammals are thought to be able to compensate for communication masking by adjusting their acoustic behavior through shifting call frequencies, increasing call volume, and increasing vocalization rates. For example in one study, blue whales increased call rates when exposed to noise from seismic surveys in the St. Lawrence Estuary (Di Iorio and Clark, 2010). Other studies reported that some North Atlantic right whales exposed to high shipping noise increased call frequency (Parks
Studies have shown that some baleen and toothed whales continue calling in the presence of seismic pulses, and some researchers have heard these calls between the seismic pulses (
In contrast, Clark and Gagnon (2006) reported that fin whales in the northeast Pacific Ocean went silent for an extended period starting soon after the onset of a seismic survey in the area. Similarly, NMFS is aware of one report that observed sperm whales ceasing calls when exposed to pulses from a very distant seismic ship (Bowles
Risch
Several studies have also reported hearing dolphins and porpoises calling while airguns were operating (
Although some degree of masking is inevitable when high levels of manmade broadband sounds are present in the sea, marine mammals have evolved systems and behavior that function to reduce the impacts of masking. Odontocete conspecifics may readily detect structured signals, such as the echolocation click sequences of small toothed whales even in the presence of strong background noise because their frequency content and temporal features usually differ strongly from those of the background noise (Au and Moore, 1988, 1990). The components of background noise that are similar in frequency to the sound signal in question primarily determine the degree of masking of that signal.
Redundancy and context can also facilitate detection of weak signals. These phenomena may help marine mammals detect weak sounds in the presence of natural or manmade noise. Most masking studies in marine mammals present the test signal and the masking noise from the same direction. The sound localization abilities of marine mammals suggest that, if signal and noise come from different directions, masking would not be as severe as the usual types of masking studies might suggest (Richardson
Toothed whales and probably other marine mammals as well, have additional capabilities besides directional hearing that can facilitate detection of sounds in the presence of background noise. There is evidence that some toothed whales can shift the dominant frequencies of their echolocation signals from a frequency range with a lot of ambient noise toward frequencies with less noise (Au
These data demonstrating adaptations for reduced masking pertain mainly to the very high frequency echolocation signals of toothed whales. There is less information about the existence of corresponding mechanisms at moderate or low frequencies or in other types of marine mammals. For example, Zaitseva
Marine mammals may behaviorally react to sound when exposed to anthropogenic noise. Reactions to sound, if any, depend on species, state of maturity, experience, current activity, reproductive state, time of day, and many other factors (Richardson
Types of behavioral reactions can include the following: changing durations of surfacing and dives, number of blows per surfacing, or moving direction and/or speed; reduced/increased vocal activities; changing/cessation of certain behavioral activities (such as socializing or feeding); visible startle response or aggressive behavior (such as tail/fluke slapping or jaw clapping); avoidance of areas where noise sources are located; and/or flight responses (
The biological significance of many of these behavioral disturbances is difficult to predict, especially if the detected disturbances appear minor. However, one could expect the consequences of behavioral modification to be biologically significant if the change affects growth, survival, and/or reproduction (
• Drastic changes in diving/surfacing patterns (such as those associated with beaked whale stranding related to exposure to military mid-frequency tactical sonar);
• Permanent habitat abandonment due to loss of desirable acoustic environment; and
• Disruption of feeding or social interaction resulting in significant energetic costs, inhibited breeding, or cow-calf separation.
The onset of behavioral disturbance from anthropogenic noise depends on both external factors (characteristics of noise sources and their paths) and the receiving animals (hearing, motivation, experience, demography) and is also difficult to predict (Richardson
Studies have shown that underwater sounds from seismic activities are often readily detectable by baleen whales in the water at distances of many kilometers (Castellote
Observers have seen various species of
Ship-based monitoring studies of baleen whales (including blue, fin, sei, minke, and whales) in the northwest Atlantic found that overall, this group had lower sighting rates during seismic versus non-seismic periods (Moulton and Holst, 2010). The authors observed that baleen whales as a group were significantly farther from the vessel during seismic compared with non-seismic periods. Moreover, the authors observed that the whales swam away more often from the operating seismic vessel (Moulton and Holst, 2010). Initial sightings of blue and minke whales were significantly farther from the vessel during seismic operations compared to non-seismic periods and the authors observed the same trend for fin whales (Moulton and Holst, 2010). Also, the authors observed that minke whales most often swam away from the vessel when seismic operations were underway (Moulton and Holst, 2010).
McDonald
Dunn and Hernandez (2009) tracked blue whales in the eastern tropical Pacific Ocean near the northern East Pacific Rise using 25 ocean-bottom-mounted hydrophones and ocean bottom seismometers during the conduct of an academic seismic survey by the R/V
Castellote
A few studies have documented reactions of migrating and feeding (but not wintering) gray whales (
Data on short-term reactions by cetaceans to impulsive noises are not necessarily indicative of long-term or biologically significant effects. It is not known whether impulsive sounds affect reproductive rate or distribution and habitat use in subsequent days or years. However, gray whales have continued to migrate annually along the west coast of North America with substantial increases in the population over recent years, despite intermittent seismic exploration (and much ship traffic) in that area for decades (Appendix A in Malme
McCauley
Data collected by observers during several of Lamont-Doherty's seismic surveys in the northwest Atlantic Ocean showed that sighting rates of humpback whales were significantly greater during non-seismic periods compared with periods when a full array was operating (Moulton and Holst, 2010). In addition, humpback whales were more likely to swim away and less likely to swim towards a vessel during seismic versus non-seismic periods (Moulton and Holst, 2010).
Humpback whales on their summer feeding grounds in southeast Alaska did not exhibit persistent avoidance when exposed to seismic pulses from a 1.64-L (100-in
Other studies have suggested that south Atlantic humpback whales wintering off Brazil may be displaced or even strand upon exposure to seismic surveys (Engel
Few systematic data are available describing reactions of toothed whales to noise pulses. However, systematic work on sperm whales is underway (
Seismic operators and protected species observers (observers) on seismic vessels regularly see dolphins and other small toothed whales near operating airgun arrays, but in general there is a tendency for most delphinids to show some avoidance of operating seismic vessels (
Captive bottlenose dolphins exhibited changes in behavior when exposed to strong pulsed sounds similar in duration to those typically used in seismic surveys (Finneran
Observers stationed on seismic vessels operating off the United Kingdom from 1997-2000 have provided data on the occurrence and behavior of various toothed whales exposed to seismic pulses (Stone, 2003; Gordon
Most studies of sperm whales exposed to airgun sounds indicate that the whale shows considerable tolerance of airgun pulses (
There are almost no specific data on the behavioral reactions of beaked whales to seismic surveys. Most beaked whales tend to avoid approaching vessels of other types (
Based on a single observation, Aguilar-Soto
Similarly, other studies have observed northern bottlenose whales remain in the general area of active seismic operations while continuing to produce high-frequency clicks when exposed to sound pulses from distant seismic surveys (Gosselin and Lawson, 2004; Laurinolli and Cochrane, 2005; Simard
Pinnipeds are not likely to show a strong avoidance reaction to the airgun sources proposed for use. Visual monitoring from seismic vessels has shown only slight (if any) avoidance of airguns by pinnipeds and only slight (if any) changes in behavior. Monitoring work in the Alaskan Beaufort Sea during 1996-2001 provided considerable information regarding the behavior of Arctic ice seals exposed to seismic pulses (Harris
Exposure to high intensity sound for a sufficient duration may result in auditory effects such as a noise-induced threshold shift—an increase in the auditory threshold after exposure to noise (Finneran
When animals exhibit reduced hearing sensitivity (
The following physiological mechanisms are thought to play a role in inducing auditory TS: Effects to sensory hair cells in the inner ear that reduce their sensitivity, modification of the chemical environment within the sensory cells, residual muscular activity in the middle ear, displacement of certain inner ear membranes, increased blood flow, and post-stimulatory reduction in both efferent and sensory neural output (Southall
PTS is considered an auditory injury (Southall
Although the published body of scientific literature contains numerous theoretical studies and discussion papers on hearing impairments that can occur with exposure to a loud sound, only a few studies provide empirical information on the levels at which noise-induced loss in hearing sensitivity occurs in non-human animals.
Recent studies by Kujawa and Liberman (2009) and Lin
For marine mammals, published data are limited to the captive bottlenose dolphin, beluga, harbor porpoise, and Yangtze finless porpoise (Finneran
Lucke
A recent study on bottlenose dolphins (Schlundt,
Marine mammal hearing plays a critical role in communication with conspecifics, and interpretation of environmental cues for purposes such as predator avoidance and prey capture. Depending on the degree (elevation of threshold in dB), duration (
Given the higher level of sound necessary to cause PTS as compared with TTS, it is considerably less likely that PTS would occur during the proposed seismic survey. Cetaceans generally avoid the immediate area around operating seismic vessels, as do some other marine mammals. Some pinnipeds show avoidance reactions to airguns, but their avoidance reactions are generally not as strong or consistent compared to cetacean reactions.
Non-auditory physical effects might occur in marine mammals exposed to strong underwater pulsed sound. Possible types of non-auditory physiological effects or injuries that theoretically might occur in mammals close to a strong sound source include stress, neurological effects, bubble formation, and other types of organ or tissue damage. Some marine mammal species (
Classic stress responses begin when an animal's central nervous system perceives a potential threat to its homeostasis. That perception triggers stress responses regardless of whether a stimulus actually threatens the animal; the mere perception of a threat is sufficient to trigger a stress response (Moberg, 2000; Sapolsky
In the case of many stressors, an animal's first and most economical (in terms of biotic costs) response is behavioral avoidance of the potential stressor or avoidance of continued exposure to a stressor. An animal's second line of defense to stressors involves the sympathetic part of the autonomic nervous system and the classic “fight or flight” response, which includes the cardiovascular system, the gastrointestinal system, the exocrine glands, and the adrenal medulla to produce changes in heart rate, blood pressure, and gastrointestinal activity that humans commonly associate with stress. These responses have a relatively short duration and may or may not have significant long-term effects on an animal's welfare.
An animal's third line of defense to stressors involves its neuroendocrine or sympathetic nervous systems; the system that has received the most study has been the hypothalamus-pituitary-adrenal system (also known as the HPA axis in mammals or the hypothalamus-pituitary-interrenal axis in fish and some reptiles). Unlike stress responses associated with the autonomic nervous system, the pituitary hormones regulate virtually all neuroendocrine functions affected by stress—including immune competence, reproduction, metabolism, and behavior. Stress-induced changes in the secretion of pituitary hormones have been implicated in failed reproduction (Moberg, 1987; Rivier, 1995), altered metabolism (Elasser
The primary distinction between stress (which is adaptive and does not normally place an animal at risk) and distress is the biotic cost of the response. During a stress response, an animal uses glycogen stores that the body quickly replenishes after alleviation of the stressor. In such circumstances, the cost of the stress response would not pose a risk to the animal's welfare. However, when an animal does not have sufficient energy reserves to satisfy the energetic costs of a stress response, it diverts energy resources from other biotic functions, which impair those functions that experience the diversion. For example, when mounting a stress response diverts energy away from growth in young animals, those animals may experience stunted growth. When mounting a stress response diverts energy from a fetus, an animal's reproductive success and fitness will suffer. In these cases, the animals will have entered a pre-pathological or pathological state called “distress” (
Relationships between these physiological mechanisms, animal behavior, and the costs of stress responses have also been documented fairly well through controlled experiment; because this physiology exists in every vertebrate that has been studied, it is not surprising that stress responses and their costs have been documented in both laboratory and free-living animals (for examples see, Holberton
For example, Jansen (1998) reported on the relationship between acoustic exposures and physiological responses that are indicative of stress responses in humans (
Hearing is one of the primary senses marine mammals use to gather information about their environment and communicate with conspecifics. Although empirical information on the relationship between sensory impairment (TTS, PTS, and acoustic masking) on marine mammals remains
Resonance effects (Gentry, 2002) and direct noise-induced bubble formations (Crum
In general, there are few data about the potential for strong, anthropogenic underwater sounds to cause non-auditory physical effects in marine mammals. Such effects, if they occur at all, would presumably be limited to short distances and to activities that extend over a prolonged period. The available data do not allow identification of a specific exposure level above which non-auditory effects can be expected (Southall
When a living or dead marine mammal swims or floats onto shore and becomes “beached” or incapable of returning to sea, the event is a “stranding” (Geraci
Marine mammals strand for a variety of reasons, such as infectious agents, biotoxicosis, starvation, fishery interaction, ship strike, unusual oceanographic or weather events, sound exposure, or combinations of these stressors sustained concurrently or in series. However, the cause or causes of most strandings are unknown (Geraci
NMFS has considered the potential for behavioral responses such as stranding and indirect injury or mortality from Lamont-Doherty's use of the multibeam echosounder. In 2013, an International Scientific Review Panel (ISRP) investigated a 2008 mass stranding of approximately 100 melon-headed whales in a Madagascar lagoon system (Southall
Navy sonars linked to avoidance reactions and stranding of cetaceans: (1) Generally have longer pulse duration than the Kongsberg EM 122; and (2) are often directed close to horizontally versus more downward for the echosounder. The area of possible influence of the echosounder is much smaller—a narrow band below the source vessel. Also, the duration of exposure for a given marine mammal can be much longer for naval sonar. During Lamont-Doherty's operations, the individual pulses will be very short, and a given mammal would not receive many of the downward-directed pulses as the vessel passes by the animal. The following section outlines possible effects of an echosounder on marine mammals.
Captive bottlenose dolphins and a beluga whale exhibited changes in behavior when exposed to 1-s tonal signals at frequencies similar to those emitted by Lamont-Doherty's echosounder and to shorter broadband pulsed signals. Behavioral changes typically involved what appeared to be deliberate attempts to avoid the sound exposure (Schlundt
Lamont-Doherty would also operate a sub-bottom profiler from the source vessel during the proposed survey. The profiler's sounds are very short pulses, occurring for one to four ms once every second. Most of the energy in the sound pulses emitted by the profiler is at 3.5 kHz, and the beam is directed downward. The sub-bottom profiler on the
Vessel movement in the vicinity of marine mammals has the potential to result in either a behavioral response or a direct physical interaction. We discuss both scenarios here.
Behavioral responses to stimuli are complex and influenced to varying degrees by a number of factors, such as species, behavioral contexts, geographical regions, source characteristics (moving or stationary, speed, direction, etc.), prior experience of the animal, and physical status of the animal. For example, studies have shown that beluga whales' reactions varied when exposed to vessel noise and traffic. In some cases, naive beluga whales exhibited rapid swimming from ice-breaking vessels up to 80 km (49.7 mi) away, and showed changes in surfacing, breathing, diving, and group composition in the Canadian high Arctic where vessel traffic is rare (Finley
In reviewing more than 25 years of whale observation data, Watkins (1986) concluded that whale reactions to vessel traffic were “modified by their previous experience and current activity: habituation often occurred rapidly, attention to other stimuli or preoccupation with other activities sometimes overcame their interest or wariness of stimuli.” Watkins noticed that over the years of exposure to ships in the Cape Cod area, minke whales changed from frequent positive interest (
Ship strikes of cetaceans can cause major wounds, which may lead to the death of the animal. An animal at the surface could be struck directly by a vessel, a surfacing animal could hit the bottom of a vessel, or a vessel's propeller could injure an animal just below the surface. The severity of injuries typically depends on the size and speed of the vessel (Knowlton and Kraus, 2001; Laist
The most vulnerable marine mammals are those that spend extended periods of time at the surface in order to restore oxygen levels within their tissues after deep dives (
An examination of all known ship strikes from all shipping sources (civilian and military) indicates vessel speed is a principal factor in whether a vessel strike results in death (Knowlton and Kraus, 2001; Laist
Entanglement can occur if wildlife becomes immobilized in survey lines, cables, nets, or other equipment that is moving through the water column. The proposed seismic survey would require towing approximately 8.0 km (4.9 mi) of equipment and cables. This size of the array generally carries a lower risk of entanglement for marine mammals. Wildlife, especially slow moving individuals, such as large whales, have a low probability of entanglement due to the low amount of slack in the lines, slow speed of the survey vessel, and onboard monitoring. Lamont-Doherty has no recorded cases of entanglement of marine mammals during their conduct of over 11 years of seismic surveys (NSF, 2015).
The primary potential impacts to marine mammal habitat and other marine species are associated with elevated sound levels produced by airguns. This section describes the potential impacts to marine mammal habitat from the specified activity.
NMFS considered the effects of the survey on marine mammal prey (
There are three types of potential effects of exposure to seismic surveys: (1) Pathological, (2) physiological, and (3) behavioral. Pathological effects involve lethal and temporary or permanent sub-lethal injury. Physiological effects involve temporary and permanent primary and secondary stress responses, such as changes in levels of enzymes and proteins. Behavioral effects refer to temporary and (if they occur) permanent changes in exhibited behavior (
The available information on the impacts of seismic surveys on marine fish is from studies of individuals or portions of a population. There have been no studies at the population scale. The studies of individual fish have often been on caged fish that were exposed to
Hastings and Popper (2005), Popper (2009), and Popper and Hastings (2009) provided recent critical reviews of the known effects of sound on fish. The following sections provide a general synopsis of the available information on the effects of exposure to seismic and other anthropogenic sound as relevant to fish. The information comprises results from scientific studies of varying degrees of rigor plus some anecdotal information. Some of the data sources may have serious shortcomings in methods, analysis, interpretation, and reproducibility that must be considered when interpreting their results (see Hastings and Popper, 2005). Potential adverse effects of the program's sound sources on marine fish are noted.
There are few data about the mechanisms and characteristics of damage impacting fish by exposure to seismic survey sounds. Peer-reviewed scientific literature has presented few data on this subject. NMFS is aware of only two papers with proper experimental methods, controls, and careful pathological investigation that implicate sounds produced by actual seismic survey airguns in causing adverse anatomical effects. One such study indicated anatomical damage, and the second indicated temporary threshold shift in fish hearing. The anatomical case is McCauley
Wardle
The National Park Service conducted an experiment of the effects of a single 700 in
For a proposed seismic survey in Southern California, USGS (1999) conducted a review of the literature on the effects of airguns on fish and fisheries. They reported a 1991 study of the Bay Area Fault system from the continental shelf to the Sacramento River, using a 10 airgun (5,828 in
Some studies have reported that mortality of fish, fish eggs, or larvae can occur close to seismic sources (Kostyuchenko, 1973; Dalen and Knutsen, 1986; Booman
The former Minerals Management Service (MMS, 2005) assessed the effects of a proposed seismic survey in Cook Inlet, Alaska. The seismic survey proposed using three vessels, each towing two, four-airgun arrays ranging from 1,500 to 2,500 in
In general, any adverse effects on fish behavior or fisheries attributable to seismic testing may depend on the species in question and the nature of the fishery (season, duration, fishing method). They may also depend on the age of the fish, its motivational state, its size, and numerous other factors that are difficult, if not impossible, to quantify at this point, given such limited data on effects of airguns on fish, particularly under realistic at-sea conditions (Lokkeborg
The existing body of information on the impacts of seismic survey sound on marine invertebrates is very limited. However, there is some unpublished and very limited evidence of the potential for adverse effects on invertebrates, thereby justifying further discussion and analysis of this issue. The three types of potential effects of exposure to seismic surveys on marine invertebrates are pathological, physiological, and behavioral. Based on the physical structure of their sensory organs, marine invertebrates appear to be specialized to respond to particle displacement components of an impinging sound field and not to the pressure component (Popper
Moriyasu
Some studies have suggested that seismic survey sound has a limited pathological impact on early developmental stages of crustaceans (Pearson
Tenera Environmental (2011) reported that Norris and Mohl (1983, summarized in Mariyasu
Andre
In examining impacts to fish and invertebrates as prey species for marine mammals, we expect fish to exhibit a range of behaviors including no reaction or habituation (Peña
In order to issue an Incidental Harassment Authorization under section 101(a)(5)(D) of the MMPA, NMFS must set forth the permissible methods of taking pursuant to such activity, and other means of effecting the least practicable adverse impact on such species or stock and its habitat, paying particular attention to rookeries, mating grounds, and areas of similar significance, and on the availability of such species or stock for taking for certain subsistence uses (where relevant).
Lamont-Doherty has reviewed the following source documents and has incorporated a suite of proposed mitigation measures into their project description.
(1) Protocols used during previous Lamont-Doherty and NSF-funded seismic research cruises as approved by us and detailed in the NSF's 2011 PEIS and 2015 draft environmental analysis;
(2) Previous incidental harassment authorizations applications and authorizations that NMFS has approved and authorized; and
(3) Recommended best practices in Richardson
To reduce the potential for disturbance from acoustic stimuli associated with the activities, Lamont-Doherty, and/or its designees have proposed to implement the following mitigation measures for marine mammals:
(1) Vessel-based visual mitigation monitoring;
(2) Proposed exclusion zones;
(3) Power down procedures;
(4) Shutdown procedures;
(5) Ramp-up procedures; and
(6) Speed and course alterations.
NMFS reviewed Lamont-Doherty's proposed mitigation measures and has proposed an additional measure to effect the least practicable adverse impact on marine mammals. They are:
(1) Expanded power down procedures for concentrations of six or more whales that do not appear to be traveling (
Lamont-Doherty would position observers aboard the seismic source vessel to watch for marine mammals near the vessel during daytime airgun operations and during any start-ups at night. Observers would also watch for marine mammals near the seismic vessel for at least 30 minutes prior to the start of airgun operations after an extended shutdown (
During seismic operations, at least four protected species observers would be aboard the
Two observers on the
The
Lamont-Doherty would immediately power down or shutdown the airguns when observers see marine mammals within or about to enter the designated exclusion zone. The observer(s) would continue to maintain watch to determine when the animal(s) are outside the exclusion zone by visual confirmation. Airgun operations would not resume until the observer has confirmed that the animal has left the zone, or if not observed after 15 minutes for species with shorter dive durations (small odontocetes and pinnipeds) or 30 minutes for species with longer dive durations (mysticetes and large odontocetes, including sperm, pygmy sperm, dwarf sperm, killer, and beaked whales).
Lamont-Doherty would use safety radii to designate exclusion zones and to estimate take for marine mammals. Table 3 shows the distances at which one would expect to receive sound levels (160-, 180-, and 190-dB,) from the airgun array and a single airgun. If the protected species visual observer detects marine mammal(s) within or about to enter the appropriate exclusion zone, the
The 180- or 190-dB level shutdown criteria are applicable to cetaceans and pinnipeds respectively as specified by NMFS (2000). Lamont-Doherty used these levels to establish the exclusion zones as presented in their application.
Lamont-Doherty used a process to develop and confirm the conservativeness of the mitigation radii for a shallow-water seismic survey in the northeast Pacific Ocean offshore Washington in 2012. Crone
A power down involves decreasing the number of airguns in use such that the radius of the 180-dB or 190-dB exclusion zone is smaller to the extent that marine mammals are no longer within or about to enter the exclusion zone. A power down of the airgun array can also occur when the vessel is moving from one seismic line to another. During a power down for mitigation, the
If the observer detects a marine mammal outside the exclusion zone and the animal is likely to enter the zone, the crew would power down the airguns to reduce the size of the 180-dB or 190-dB exclusion zone before the animal enters that zone. Likewise, if a mammal is already within the zone after detection, the crew would power-down the airguns immediately. During a power down of the airgun array, the crew would operate a single 40-in
Following a power-down, the
• The observer has visually observed the animal leave the exclusion zone; or
• An observer has not sighted the animal within the exclusion zone for 15 minutes for species with shorter dive durations (
The
NMFS estimates that the
The
(1) If an animal enters the exclusion zone of the single airgun after the crew has initiated a power down; or
(2) If an observer sees the animal is initially within the exclusion zone of
During periods of active seismic operations, there are occasions when the
If the full exclusion zone is not visible to the observer for at least 30 minutes prior to the start of operations in either daylight or nighttime, the
If one airgun has operated during a power down period, ramp-up to full power would be permissible at night or in poor visibility, on the assumption that marine mammals would be alerted to the approaching seismic vessel by the sounds from the single airgun and could move away. The vessel's crew would not initiate a ramp-up of the airguns if an observer sees the marine mammal within or near the applicable exclusion zones during the day or close to the vessel at night.
Ramp-up of an airgun array provides a gradual increase in sound levels, and involves a step-wise increase in the number and total volume of airguns firing until the full volume of the airgun array is achieved. The purpose of a ramp-up is to “warn” marine mammals in the vicinity of the airguns, and to provide the time for them to leave the area and thus avoid any potential injury or impairment of their hearing abilities. Lamont-Doherty would follow a ramp-up procedure when the airgun array begins operating after an 8 minute period without airgun operations or when shut down has exceeded that period. Lamont-Doherty has used similar waiting periods (approximately eight to 10 minutes) during previous seismic surveys.
Ramp-up would begin with the smallest airgun in the array (40-in
If the complete exclusion zone has not been visible for at least 30 minutes prior to the start of operations in either daylight or nighttime, Lamont-Doherty would not commence the ramp-up unless at least one airgun (40-in
The
If during seismic data collection, Lamont-Doherty detects marine mammals outside the exclusion zone and, based on the animal's position and direction of travel, is likely to enter the exclusion zone, the
NMFS has carefully evaluated Lamont-Doherty's proposed mitigation measures in the context of ensuring that we prescribe the means of effecting the least practicable impact on the affected marine mammal species and stocks and their habitat. Our evaluation of potential measures included consideration of the following factors in relation to one another:
• The manner in which, and the degree to which, the successful implementation of the measure is expected to minimize adverse impacts to marine mammals;
• The proven or likely efficacy of the specific measure to minimize adverse impacts as planned; and
• The practicability of the measure for applicant implementation.
Any mitigation measure(s) prescribed by NMFS should be able to accomplish, have a reasonable likelihood of accomplishing (based on current science), or contribute to the accomplishment of one or more of the general goals listed here:
1. Avoidance or minimization of injury or death of marine mammals wherever possible (goals 2, 3, and 4 may contribute to this goal).
2. A reduction in the numbers of marine mammals (total number or number at biologically important time or location) exposed to airgun operations that we expect to result in the take of marine mammals (this goal may contribute to 1, above, or to reducing harassment takes only).
3. A reduction in the number of times (total number or number at biologically important time or location) individuals would be exposed to airgun operations that we expect to result in the take of marine mammals (this goal may contribute to 1, above, or to reducing harassment takes only).
4. A reduction in the intensity of exposures (either total number or number at biologically important time or location) to airgun operations that we expect to result in the take of marine mammals (this goal may contribute to a, above, or to reducing the severity of harassment takes only).
5. Avoidance or minimization of adverse effects to marine mammal habitat, paying special attention to the food base, activities that block or limit passage to or from biologically important areas, permanent destruction of habitat, or temporary destruction/disturbance of habitat during a biologically important time.
6. For monitoring directly related to mitigation—an increase in the probability of detecting marine mammals, thus allowing for more effective implementation of the mitigation.
Based on the evaluation of Lamont-Doherty's proposed measures, as well as other measures proposed by NMFS (
In order to issue an Incidental Harassment Authorization for an activity, section 101(a)(5)(D) of the MMPA states that NMFS must set forth “requirements pertaining to the monitoring and reporting of such taking.” The MMPA implementing regulations at 50 CFR 216.104 (a)(13) indicate that requests for Authorizations must include the suggested means of accomplishing the necessary monitoring and reporting that will result in increased knowledge of the species and of the level of taking or impacts on populations of marine mammals that we expect to be present in the proposed action area.
Lamont-Doherty submitted a marine mammal monitoring plan in section XIII of the Authorization application. NMFS, NSF, or Lamont-Doherty may modify or supplement the plan based on comments or new information received from the public during the public comment period.
Monitoring measures prescribed by NMFS should accomplish one or more of the following general goals:
1. An increase in the probability of detecting marine mammals, both within the mitigation zone (thus allowing for more effective implementation of the mitigation) and during other times and locations, in order to generate more data to contribute to the analyses mentioned later;
2. An increase in our understanding of how many marine mammals would be affected by seismic airguns and other active acoustic sources and the likelihood of associating those exposures with specific adverse effects, such as behavioral harassment, temporary or permanent threshold shift;
3. An increase in our understanding of how marine mammals respond to stimuli that we expect to result in take and how those anticipated adverse effects on individuals (in different ways and to varying degrees) may impact the population, species, or stock (specifically through effects on annual rates of recruitment or survival) through any of the following methods:
a. Behavioral observations in the presence of stimuli compared to observations in the absence of stimuli (
b. Physiological measurements in the presence of stimuli compared to observations in the absence of stimuli (
c. Distribution and/or abundance comparisons in times or areas with concentrated stimuli versus times or areas without stimuli;
4. An increased knowledge of the affected species; and
5. An increase in our understanding of the effectiveness of certain mitigation and monitoring measures.
Lamont-Doherty proposes to sponsor marine mammal monitoring during the present project to supplement the mitigation measures that require real-time monitoring, and to satisfy the monitoring requirements of the Authorization. Lamont-Doherty understands that NMFS would review the monitoring plan and may require refinements to the plan. Lamont-Doherty planned the monitoring work as a self-contained project independent of any other related monitoring projects that may occur in the same regions at the same time. Further, Lamont-Doherty is prepared to discuss coordination of its monitoring program with any other related work that might be conducted by other groups working insofar as it is practical for Lamont-Doherty.
Passive acoustic monitoring would complement the visual mitigation monitoring program, when practicable. Visual monitoring typically is not effective during periods of poor visibility or at night, and even with good visibility, is unable to detect marine mammals when they are below the surface or beyond visual range. Passive acoustical monitoring can improve detection, identification, and localization of cetaceans when used in conjunction with visual observations. The passive acoustic monitoring would serve to alert visual observers (if on duty) when vocalizing cetaceans are detected. It is only useful when marine mammals call, but it can be effective either by day or by night, and does not depend on good visibility. The acoustic observer would monitor the system in real time so that he/she can advise the visual observers if they acoustically detect cetaceans.
The passive acoustic monitoring system consists of hardware (
One acoustic observer, an expert bioacoustician with primary responsibility for the passive acoustic monitoring system would be aboard the
One acoustic observer would monitor the acoustic detection system by listening to the signals from two channels via headphones and/or speakers and watching the real-time spectrographic display for frequency ranges produced by cetaceans. The observer monitoring the acoustical data would be on shift for one to six hours at a time. The other observers would rotate as an acoustic observer, although the expert acoustician would be on passive acoustic monitoring duty more frequently.
When the acoustic observer detects a vocalization while visual observations are in progress, the acoustic observer on duty would contact the visual observer immediately, to alert him/her to the presence of cetaceans (if they have not already been seen), so that the vessel's crew can initiate a power down or shutdown, if required. The observer would enter the information regarding the call into a database. Data entry would include an acoustic encounter identification number, whether it was linked with a visual sighting, date, time when first and last heard and whenever any additional information was recorded, position and water depth when first detected, bearing if determinable, species or species group (
Observers would record data to estimate the numbers of marine mammals exposed to various received sound levels and to document apparent disturbance reactions or lack thereof. They would use the data to help better understand the impacts of the activity on marine mammals and to estimate numbers of animals potentially `taken' by harassment (as defined in the MMPA). They will also provide information needed to order a power down or shut down of the airguns when a marine mammal is within or near the exclusion zone.
When an observer makes a sighting, they will record the following information:
1. Species, group size, age/size/sex categories (if determinable), behavior when first sighted and after initial sighting, heading (if consistent), bearing and distance from seismic vessel, sighting cue, apparent reaction to the airguns or vessel (
2. Time, location, heading, speed, activity of the vessel, sea state, visibility, and sun glare.
The observer will record the data listed under (2) at the start and end of each observation watch, and during a watch whenever there is a change in one or more of the variables.
Observers will record all observations and power downs or shutdowns in a standardized format and will enter data into an electronic database. The observers will verify the accuracy of the data entry by computerized data validity checks during data entry and by subsequent manual checking of the database. These procedures will allow the preparation of initial summaries of data during and shortly after the field program, and will facilitate transfer of the data to statistical, graphical, and other programs for further processing and archiving.
Results from the vessel-based observations will provide:
1. The basis for real-time mitigation (airgun power down or shutdown).
2. Information needed to estimate the number of marine mammals potentially taken by harassment, which Lamont-Doherty must report to the Office of Protected Resources.
3. Data on the occurrence, distribution, and activities of marine mammals and turtles in the area where Lamont-Doherty would conduct the seismic study.
4. Information to compare the distance and distribution of marine mammals and turtles relative to the source vessel at times with and without seismic activity.
5. Data on the behavior and movement patterns of marine mammals detected during non-active and active seismic operations.
Lamont-Doherty would submit a report to us and to NSF within 90 days after the end of the cruise. The report would describe the operations conducted and sightings of marine mammals near the operations. The report would provide full documentation of methods, results, and interpretation pertaining to all monitoring. The 90-day report would summarize the dates and locations of seismic operations, and all marine mammal sightings (dates, times, locations, activities, associated seismic survey activities). The report would also include estimates of the number and nature of exposures that occurred above
In the unanticipated event that the specified activity clearly causes the take of a marine mammal in a manner not permitted by the authorization (if issued), such as an injury, serious injury, or mortality (
• Time, date, and location (latitude/longitude) of the incident;
• Name and type of vessel involved;
• Vessel's speed during and leading up to the incident;
• Description of the incident;
• Status of all sound source use in the 24 hours preceding the incident;
• Water depth;
• Environmental conditions (
• Description of all marine mammal observations in the 24 hours preceding the incident;
• Species identification or description of the animal(s) involved;
• Fate of the animal(s); and
• Photographs or video footage of the animal(s) (if equipment is available).
Lamont-Doherty shall not resume its activities until we are able to review the circumstances of the prohibited take. We shall work with Lamont-Doherty to determine what is necessary to minimize the likelihood of further prohibited take and ensure MMPA compliance. Lamont-Doherty may not resume their activities until notified by us via letter, email, or telephone.
In the event that Lamont-Doherty discovers an injured or dead marine mammal, and the lead visual observer determines that the cause of the injury or death is unknown and the death is relatively recent (
In the event that Lamont-Doherty discovers an injured or dead marine mammal, and the lead visual observer determines that the injury or death is not associated with or related to the authorized activities (
Except with respect to certain activities not pertinent here, section 3(18) 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].
Acoustic stimuli (
NMFS' practice is to apply the 160 dB re: 1 µPa received level threshold for underwater impulse sound levels to predict whether behavioral disturbance that rises to the level of Level B harassment is likely to occur. NMFS' practice is to apply the 180 dB or 190 dB re: 1 µPa received level threshold for underwater impulse sound levels to predict whether permanent threshold shift (auditory injury), which we consider as Level A harassment is likely to occur.
Given the many uncertainties in predicting the quantity and types of impacts of sound on marine mammals, it is common practice to estimate how many animals are likely to be present within a particular distance of a given activity, or exposed to a particular level of sound and use that information to predict how many animals are taken. In practice, depending on the amount of information available to characterize daily and seasonal movement and distribution of affected marine mammals, distinguishing between the numbers of individuals harassed and the instances of harassment can be difficult to parse. Moreover, when one considers the duration of the activity, in the absence of information to predict the degree to which individual animals are likely exposed repeatedly on subsequent days, the simple assumption is that entirely new animals are exposed in every day, which results in a take estimate that in some circumstances overestimates the number of individuals harassed.
The following sections describe NMFS' methods to estimate take by incidental harassment. We base these estimates on the number of marine
(1) Calculate the total area that the
(2) Multiply each daily ensonified area above the 160-dB Level B harassment threshold by the species' density (animals/km
(3) Multiply each product (
(4) Multiply the daily ensonified area by each species-specific density to derive the predicted number of instances of exposures to received levels greater than or equal to 180-dB re: 1 μPa for cetaceans on a given day (
(5) Multiply each product by the number of survey days that includes a 25 percent contingency (
In many cases, this estimate of instances of exposures is likely an overestimate of the number of individuals that are taken, because it assumes 100 percent turnover in the area every day, (
NMFS used sighting information from a survey off Namibia, Africa (Rose and Payne, 1991) to estimate a mean group size for southern right whale dolphins (58) and also multiplied that estimate by 28 days to derive an estimate of take from a potential encounter with that species.
Lamont-Doherty did not estimate any additional take from sound sources other than airguns. NMFS does not expect the sound levels produced by the echosounder and sub-bottom profiler to exceed the sound levels produced by the airguns. Lamont-Doherty will not operate the multibeam echosounder and sub-bottom profiler during transits to and from the survey area, (
NMFS considers the probability for entanglement of marine mammals as low because of the vessel speed and the monitoring efforts onboard the survey vessel. Therefore, NMFS does not believe it is necessary to authorize additional takes for entanglement at this time.
The
There is no evidence that the planned survey activities could result in serious injury or mortality within the specified geographic area for the requested proposed Authorization. The required mitigation and monitoring measures would minimize any potential risk for serious injury or mortality.
Negligible impact is “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” (50 CFR 216.103). The lack of likely adverse effects on annual rates of recruitment or survival (
In making a negligible impact determination, NMFS considers:
• The number of anticipated injuries, serious injuries, or mortalities;
• The number, nature, and intensity, and duration of harassment; and
• The context in which the takes occur (
• The status of stock or species of marine mammals (
• Impacts on habitat affecting rates of recruitment/survival; and
• The effectiveness of monitoring and mitigation measures to reduce the number or severity of incidental takes.
To avoid repetition, our analysis applies to all the species listed in Table 5, given that NMFS expects the anticipated effects of the seismic airguns to be similar in nature. Where there are meaningful differences between species or stocks, or groups of species, in anticipated individual responses to activities, impact of expected take on the population due to differences in population status, or impacts on habitat, NMFS has identified species-specific factors to inform the analysis.
Given the required mitigation and related monitoring, NMFS does not anticipate that serious injury or mortality would occur as a result of Lamont-Doherty's proposed seismic survey in the South Atlantic Ocean. Thus the proposed authorization does not authorize any mortality.
NMFS' predicted estimates for Level A harassment take for some species are likely overestimates of the injury that will occur. NMFS expects that successful implementation of the required visual and acoustic mitigation measures would avoid Level A take in some instances. Also, NMFS expects that some individuals would avoid the source at levels expected to result in injury. Nonetheless, although NMFS expects that Level A harassment is unlikely to occur at the numbers proposed to be authorized, because it is difficult to quantify the degree to which the mitigation and avoidance will reduce the number of animals that might incur PTS, we are proposing to authorize (and analyze) the modeled number of Level A takes, which does not take the mitigation or avoidance into consideration. However, because of the constant movement of the
Of the marine mammal species under our jurisdiction that are known to occur or likely to occur in the study area, the following species are listed as endangered under the ESA: blue, fin, humpback, sei, Southern right whale, and sperm whales. The western north Atlantic population of humpback whales is known to be increasing. The other marine mammal species that may be taken by harassment during Lamont-Doherty's seismic survey program are not listed as threatened or endangered under the ESA.
Potential impacts to marine mammal habitat were discussed previously in this document (see the “Anticipated Effects on Habitat” section). Although some disturbance is possible to food sources of marine mammals, the impacts are anticipated to be minor enough as to not affect annual rates of recruitment or survival of marine mammals in the area. Based on the size of the South Atlantic Ocean where feeding by marine mammals occurs versus the localized area of the marine survey activities, any missed feeding opportunities in the direct project area will be minor based on the fact that other feeding areas exist elsewhere. Taking into account the planned mitigation measures, effects on cetaceans are generally expected to be restricted to avoidance of a limited area around the survey operation and short-term changes in behavior, falling within the MMPA definition of “Level B harassment.” Animals are not expected to permanently abandon any area that is surveyed, and any behaviors that are interrupted during the activity are expected to resume once the activity ceases. Only a small portion of marine mammal habitat will be affected at any time, and other areas within the South Atlantic Ocean would be available for necessary biological functions.
Many animals perform vital functions, such as feeding, resting, traveling, and socializing, on a diel cycle (
For reasons stated previously in this document and based on the following factors, Lamont-Doherty's specified activities are not likely to cause long-term behavioral disturbance, serious injury, or death, or other effects that would be expected to adversely affect reproduction or survival of any individuals. They include:
• The anticipated impacts of Lamont-Doherty's survey activities on marine mammals are temporary behavioral changes due, primarily, to avoidance of the area;
• The likelihood that, given the constant movement of boat and animals and the nature of the survey design (not concentrated in areas of high marine mammal concentration), PTS incurred would be of a low level;
• The availability of alternate areas of similar habitat value for marine mammals to temporarily vacate the survey area during the operation of the airgun(s) to avoid acoustic harassment;
• The expectation that the seismic survey would have no more than a temporary and minimal adverse effect on any fish or invertebrate species that serve as prey species for marine mammals, and therefore consider the potential impacts to marine mammal habitat minimal; and
• The knowledge that the survey is taking place in the open ocean and not located within an area of biological importance for breeding, calving, or foraging for marine mammals.
Table 5 in this document outlines the number of requested Level A and Level B harassment takes that we anticipate as a result of these activities.
Required mitigation measures, such as special shutdowns for large whales, vessel speed, course alteration, and visual monitoring would be implemented to help reduce impacts to marine mammals. Based on the analysis herein of the likely effects of the specified activity on marine mammals and their habitat, and taking into consideration the implementation of the proposed monitoring and mitigation measures, NMFS finds that Lamont-Doherty's proposed seismic survey would have a negligible impact on the affected marine mammal species or stocks.
As mentioned previously, NMFS estimates that Lamont-Doherty's activities could potentially affect, by Level B harassment, 38 species of marine mammals under our jurisdiction. NMFS estimates that Lamont-Doherty's activities could potentially affect, by Level A harassment, up to 16 species of marine mammals under our jurisdiction.
For each species, the numbers of take being proposed for authorization are small numbers relative to the population sizes: less than 16 percent for striped dolphins, less than 8 percent of Risso's dolphins, less than 6 percent for pantropical spotted dolphins, and less than 4 percent for all other species. NMFS has provided the regional population and take estimates for the marine mammal species that may be taken by Level A and Level B harassment in Table 5 in this notice. NMFS finds that the proposed incidental take described in Table 5 for the proposed activity would be limited to small numbers relative to the affected species or stocks.
There are no relevant subsistence uses of marine mammals implicated by this action.
There are six marine mammal species listed as endangered under the Endangered Species Act that may occur in the proposed survey area. Under section 7 of the ESA, NSF has initiated formal consultation with NMFS on the proposed seismic survey. NMFS (
NSF has prepared a draft environmental analysis titled,
As a result of these preliminary determinations, NMFS proposes issuing an Authorization to Lamont-Doherty for conducting a seismic survey in the South Atlantic Ocean, early January through March 31, 2016 provided they incorporate the proposed mitigation, monitoring, and reporting requirements.
This section contains the draft text for the proposed Authorization. NMFS proposes to include this language in the Authorization if issued.
We hereby authorize the Lamont-Doherty Earth Observatory (Lamont-Doherty), Columbia University, P.O. Box 1000, 61 Route 9W, Palisades, New York 10964-8000, under section 101(a)(5)(D) of the Marine Mammal Protection Act (MMPA) (16 U.S.C. 1371(a)(5)(D)) and 50 CFR 216.107, to incidentally harass small numbers of marine mammals incidental to a marine geophysical survey conducted by the R/V
This Authorization is valid from early January through March 31, 2016.
This Authorization is valid only for specified activities associated with the R/V
a. in the South Atlantic Ocean, located approximately between 10-35 °W, 27-33 °S as specified in Lamont-Doherty's application and the National Science Foundation's environmental analysis.
a. This authorization limits the incidental taking of marine mammals, by harassment only, to the following species in the area described in Table 5 in this notice.
i. During the seismic activities, if the Holder of this Authorization encounters any marine mammal species that are not listed in Condition 3 for authorized taking and are likely to be exposed to sound pressure levels greater than or equal to 160 decibels (dB) re: 1 μPa, then the Holder must alter speed or course or shut-down the airguns to avoid take.
b. The taking by serious injury or death of any of the species listed in Condition 3 or the taking of any kind of any other species of marine mammal is prohibited and may result in the modification, suspension, or revocation of this Authorization.
c. This Authorization limits the methods authorized for taking by harassment to the following acoustic sources:
i. a sub-airgun array with a total capacity of 6,600 in
The Holder of this Authorization must report the taking of any marine mammal in a manner prohibited under this Authorization immediately to the Office of Protected Resources, National Marine Fisheries Service, at 301-427-8401 and/or by email to the Chief, Permits and Conservation Division.
We require the Holder of this Authorization to cooperate with the Office of Protected Resources, National Marine Fisheries Service, and any other Federal, state, or local agency monitoring the impacts of the activity on marine mammals.
We require the Holder of this Authorization to implement the following mitigation and monitoring requirements when conducting the specified activities to achieve the least practicable adverse impact on affected marine mammal species or stocks:
a. Utilize two, National Marine Fisheries Service-qualified, vessel-based Protected Species Visual Observers (visual observers) to watch for and monitor marine mammals near the seismic source vessel during daytime airgun operations (from nautical twilight-dawn to nautical twilight-dusk) and before and during start-ups of airguns day or night.
i. At least one visual observer will be on watch during meal times and restroom breaks.
ii. Observer shifts will last no longer than four hours at a time.
iii. Visual observers will also conduct monitoring while the
iv. When feasible, visual observers will conduct observations during daytime periods when the seismic system is not operating for comparison of sighting rates and behavioral reactions during, between, and after airgun operations.
v. The
b. Establish a 180-decibel (dB) or 190-dB exclusion zone for cetaceans and pinnipeds, respectively, before starting the airgun subarray (6,660 in
c. Monitor the entire extent of the exclusion zones for at least 30 minutes (day or night) prior to the ramp-up of airgun operations after a shutdown.
d. Delay airgun operations if the visual observer sees a cetacean within the 180-dB exclusion zone for cetaceans or 190-dB exclusion zone for pinnipeds until the marine mammal(s) has left the area.
i. If the visual observer sees a marine mammal that surfaces, then dives below the surface, the observer shall wait 30 minutes. If the observer sees no marine mammals during that time, he/she should assume that the animal has moved beyond the 180-dB exclusion zone for cetaceans or 190-dB exclusion zone for pinnipeds.
ii. If for any reason the visual observer cannot see the full 180-dB exclusion zone for cetaceans or the 190-dB exclusion zone for pinnipeds for the entire 30 minutes (
iii. If one airgun is already running at a source level of at least 180 dB re: 1 μPa or 190 dB re: 1 μPa, the
e. Utilize the passive acoustic monitoring (PAM) system, to the maximum extent practicable, to detect and allow some localization of marine mammals around the
f. Do and record the following when an observer detects an animal by the PAM:
i. notify the visual observer immediately of a vocalizing marine mammal so a power-down or shut-down can be initiated, if required;
ii. enter the information regarding the vocalization into a database. The data to be entered include an acoustic encounter identification number, whether it was linked with a visual sighting, date, time when first and last heard and whenever any additional information was recorded, position, water depth when first detected, bearing if determinable, species or species group (
g. Implement a “ramp-up” procedure when starting the airguns at the beginning of seismic operations or any time after the entire array has been shutdown, which means start the smallest gun first and add airguns in a sequence such that the source level of the array will increase in steps not exceeding approximately 6 dB per 5-minute period. During ramp-up, the observers will monitor the exclusion zone, and if marine mammals are sighted, a course/speed alteration, power-down, or shutdown will be implemented as though the full array were operational.
h. Visual observers must record the following information when they have sighted a marine mammal:
i. Species, group size, age/size/sex categories (if determinable), behavior when first sighted and after initial sighting, heading (if consistent), bearing and distance from seismic vessel, sighting cue, apparent reaction to the airguns or vessel (
ii. Time, location, heading, speed, activity of the vessel (including number of airguns operating and whether in state of ramp-up or shut-down), Beaufort sea state and wind force, visibility, and sun glare; and
iii. The data listed under 6(f)(ii) at the start and end of each observation watch and during a watch whenever there is a change in one or more of the variables.
i. Alter speed or course during seismic operations if a marine mammal, based on its position and relative motion, appears likely to enter the relevant exclusion zone. If speed or course alteration is not safe or practicable, or if after alteration the marine mammal still appears likely to enter the exclusion zone, the Holder of this Authorization will implement further mitigation measures, such as a shutdown.
j. Power down the airguns if a visual observer detects a marine mammal within, approaching, or entering the relevant exclusion zones. A power-down means reducing the number of operating airguns to a single operating 40 in
k. Following a power-down, if the marine mammal approaches the smaller designated exclusion zone, the airguns must then be completely shut-down. Airgun activity will not resume until the observer has visually observed the marine mammal(s) exiting the exclusion zone and is not likely to return, or has not been seen within the exclusion zone for 15 minutes for species with shorter dive durations (small odontocetes) or 30 minutes for species with longer dive durations (mysticetes and large odontocetes, including sperm, pygmy sperm, dwarf sperm, killer, and beaked whales).
l. Following a power-down and subsequent animal departure, the
m. Shutdown the airgun(s) if a visual observer detects a marine mammal within, approaching, or entering the relevant exclusion zone. A shutdown means that the
n. Following a shutdown, if the observer has visually confirmed that the animal has departed the 180-dB zone for cetaceans or the 190-dB zone for pinnipeds within a period of less than or equal to 8 minutes after the shutdown, then the
o. If the observer has not seen the animal depart the 180-dB zone for cetaceans or the 190-dB zone for pinnipeds, the
p. The
q. This Authorization does not permit the Holder of this Authorization to initiate airgun array operations from a shut-down position at night or during low-light hours (such as in dense fog or heavy rain) when the visual observers cannot view and effectively monitor the full relevant exclusion zones.
s. The
t. The
This Authorization requires the Holder of this Authorization to:
a. Submit a draft report on all activities and monitoring results to the Office of Protected Resources, National Marine Fisheries Service, within 90 days of the completion of the
i. Dates, times, locations, heading, speed, weather, sea conditions (including Beaufort sea state and wind force), and associated activities during all seismic operations and marine mammal sightings.
ii. Species, number, location, distance from the vessel, and behavior of any marine mammals, as well as associated seismic activity (number of shutdowns), observed throughout all monitoring activities.
iii. An estimate of the number (by species) of marine mammals with known exposures to the seismic activity (based on visual observation) at received
iv. An estimate of the number (by species) of marine mammals with estimated exposures (based on modeling results) to the seismic activity at received levels greater than or equal to 160 dB re: 1 μPa and/or 180 dB re 1 μPa for cetaceans and 190-dB re 1 μPa for pinnipeds with a discussion of the nature of the probable consequences of that exposure on the individuals.
v. A description of the implementation and effectiveness of the: (A) terms and conditions of the Biological Opinion's Incidental Take Statement (attached); and (B) mitigation measures of the Incidental Harassment Authorization. For the Biological Opinion, the report will confirm the implementation of each Term and Condition, as well as any conservation recommendations, and describe their effectiveness, for minimizing the adverse effects of the action on Endangered Species Act listed marine mammals.
b. Submit a final report to the Chief, Permits and Conservation Division, Office of Protected Resources, National Marine Fisheries Service, within 30 days after receiving comments from us on the draft report. If we decide that the draft report needs no comments, we will consider the draft report to be the final report.
In the unanticipated event that the specified activity clearly causes the take of a marine mammal in a manner not permitted by the authorization (if issued), such as an injury, serious injury, or mortality (
• Time, date, and location (latitude/longitude) of the incident;
• Name and type of vessel involved;
• Vessel's speed during and leading up to the incident;
• Description of the incident;
• Status of all sound source use in the 24 hours preceding the incident;
• Water depth;
• Environmental conditions (
• Description of all marine mammal observations in the 24 hours preceding the incident;
• Species identification or description of the animal(s) involved;
• Fate of the animal(s); and
• Photographs or video footage of the animal(s) (if equipment is available).
Lamont-Doherty shall not resume its activities until we are able to review the circumstances of the prohibited take. We shall work with Lamont-Doherty to determine what is necessary to minimize the likelihood of further prohibited take and ensure MMPA compliance. Lamont-Doherty may not resume their activities until notified by us via letter, email, or telephone.
In the event that Lamont-Doherty discovers an injured or dead marine mammal, and the lead visual observer determines that the cause of the injury or death is unknown and the death is relatively recent (
In the event that Lamont-Doherty discovers an injured or dead marine mammal, and the lead visual observer determines that the injury or death is not associated with or related to the authorized activities (
Lamont-Doherty is required to comply with the Terms and Conditions of the Incidental Take Statement corresponding to the Endangered Species Act Biological Opinion issued to the National Science Foundation and NMFS' Office of Protected Resources, Permits and Conservation Division (attached). A copy of this Authorization and the Incidental Take Statement must be in the possession of all contractors and protected species observers operating under the authority of this Incidental Harassment Authorization.
NMFS invites comments on our analysis, the draft authorization, and any other aspect of the Notice of proposed Authorization for Lamont-Doherty's activities. Please include any supporting data or literature citations with your comments to help inform our final decision on Lamont-Doherty's request for an application.
On March 15, 2013, Bloomberg STP LLC (“BSTP”) filed with the Securities and Exchange Commission (“Commission”) an application on Form CA-1 for an exemption from registration as a clearing agency (“BSTP application”) pursuant to Section 17A of the Securities Exchange Act of 1934 (“Exchange Act”) and Rule 17Ab2-1 thereunder. BSTP amended the BSTP application on May 7, 9, and 10, July 11, August 8, September 18, and November 21, 2013, December 19, 2014, and January 22, 2015.
On April 15, 2013, SS&C Technologies, Inc. (“SS&C”) filed with the Commission an application on Form CA-1 for an exemption from registration as a clearing agency (“SS&C application”) pursuant to Section 17A of the Exchange Act and Rule 17Ab2-1 thereunder. SS&C amended the SS&C application on August 12, 2013, December 23, 2014, March 30, 2015, and November 9, 2015.
In addition, in the November 9, 2015 amendment SS&C replaced a representation stating that SS&C shall comply with the White Paper on Sound Practices to Strengthen the Resilience of the U.S. Financial System before its volume for U.S. securities matched is 1% of the U.S. aggregate daily share volume with a representation stating that SS&C understands that in offering its ETC services and matching services it will be defined as an “SCI entity” under Regulation Systems, Compliance, and Integrity (“Regulation SCI”) and, as such, that it will operate in compliance with applicable obligations under Regulation SCI.
In all, the Commission received thirty comment letters in response to the BSTP and SS&C applications. Among these comment letters, the Commission received twenty-seven in response to the BSTP application, including two from BSTP itself, and three comment letters on the SS&C application, including one from SS&C itself.
BSTP is a limited liability company organized under the laws of the State of Delaware and is wholly-owned by Bloomberg L.P. (“BLP”).
The BSTP application states that BSTP will enter into a Software License Agreement and a License and Services Agreement with BLP. Under the terms and conditions of such agreements, BLP will provide BSTP with software, hardware, administrative, operational, and other support services, and BSTP will retain ultimate legal responsibility for its operations. BSTP has also established a board of directors to oversee its operations, and the BSTP application states that it will establish
The BSTP application proposes a matching service that will compare post-trade information from a broker-dealer (the firm) and the broker-dealer's institutional customer and reconcile such information to generate an affirmed confirmation, operating as follows according to the BSTP application:
1. A customer routes an order to its firm.
2. The firm executes the order and then sends a notice of execution (“NOE”) to the customer.
3. For voice executed trades, the customer affirms to the firm the trade details contained in the NOE. For trades executed electronically, the electronic trading platform records the trade in the blotters of the customer and the firm.
4. The customer sends to the matching service, the firm, and the customer's custodian allocation information for the trade.
5. The firm then submits to the matching service trade data corresponding to each allocation, including settlement instructions and, as applicable, commissions, taxes, and fees.
6. The matching service next compares the customer's allocation information (containing multiple fields of data) with the firm's trade data to determine whether the information contained in each field matches. If all required fields match, the matching service generates a matched confirmation and sends it to the firm, the customer, and other entities designated by the customer (
7. After the matching service creates the matched confirmation, the matching service submits it to The Depository Trust Company (“DTC”) as an “affirmed confirmation.” From there, the trade goes into DTC's settlement process.
Other than the matching service, the BSTP application states that BSTP will not perform any other functions of a clearing agency requiring registration under Section 17A of the Exchange Act, such as net settlement, maintaining a balance of open positions between buyers and sellers, marking securities to the market, or handling funds or securities.
SS&C was incorporated in Delaware in 1996 and has headquarters in Windsor, Connecticut, with offices in 20 locations across the United States and additional offices in Toronto, Canada, and other locations throughout the world. SS&C is a global provider of financial services-related solutions to investment management, banking, and other financial sector clients. All control and direction over SS&C is vested in SS&C Technologies Holdings, Inc. (“SS&C Holdings”), SS&C's parent company and a public holding company listed on NASDAQ (symbol SSNC).
The SS&C application states that all matching services would be performed by SS&C's subsidiary, SS&C Technologies Canada Corp. (“SS&C Canada”). The policies and operations of SS&C Canada are overseen by its officers and directors, and are subject to control by SS&C Holdings. SS&C Canada will perform the matching services in Mississauga, Canada, through its software-enabled service, SSCNet, which is a global trade network linking investment managers, broker-dealers, clearing agencies, custodians, and interested parties. Client support for these services will be rendered through SS&C's offices in the United States, the United Kingdom, and Australia. SS&C will coordinate support activity, which includes help desk facilities and call and issue tracking through a shared client call database, and relationship management. SS&C and SS&C Canada will maintain an intercompany agreement setting forth respective services and obligations.
In addition, the SS&C application makes the following representations regarding SS&C's operations: (i) SS&C shall obtain contractual commitments from its customers permitting it to provide information to the Ontario Securities Commission, the Commission, and other third parties; (ii) SS&C shall make available SS&C Canada employees in Canada or the United States for interview by the Commission subject to reasonable notice, provided that such action does not impose unreasonable hardship under applicable immigration law on such employees; (iii) as set forth in the intercompany agreement, SS&C shall provide the Commission access to information related to SS&C's matching system and ETC services, including those documents it receives from its service provider, SS&C Canada (the “business activities information”); (iv) SS&C Canada shall provide on the same business day to SS&C at its headquarters in Windsor, Connecticut electronically generated business activities information, in whatever form SS&C shall specify, including regularly and automatically generated and ad hoc reports, books and records, correspondence, memoranda, papers, notices, accounts, and other such records; and (v) SS&C Canada shall send to SS&C at its headquarters in Windsor, Connecticut, all manually generated business activities information, in whatever form SS&C shall specify, no later than the business day on which the record is generated. Further, SS&C has confirmed with external counsel that implementation of the intercompany agreement would not violate the Canadian Personal Information Protection and Electronic Documents Act or the Ontario Business Records Protection Act.
Like the BSTP application, the SS&C application proposes to provide matching and ETC services for broker-dealers and institutional customers that will allow such entities to streamline communications and process allocation and post-trade information for fixed-income and equity trades for depository-eligible U.S. securities. According to the SS&C application, SS&C's matching service would allow institutional customers to route an order to a broker, receive an execution notice from the broker, and enter trade details and allocations so that SS&C's matching service can generate a matched confirmation and send an affirmed confirmation to the depository at DTC. SS&C's matching service will offer both block level matching and detail level matching. Standing settlement instructions are provided through the Delivery Instruction Database, which is fully integrated into SSCNet, and provides a repository for settlement instructions across asset classes, including foreign exchange and term deposits. SSCNet is also integrated into the Society for Worldwide Interbank Financial Telecommunication (“SWIFT”) Network, allowing users to communicate with parties outside the SSCNet platform. Users can select the output format for batch communications (SSCNet proprietary, SWIFT, ISITC, or DTC affirmation format), as well as when the batch should be submitted. Once a transaction is exported from SSCNet, central time stamping and a full audit trail are available for all transactions, with transaction histories maintained online for a minimum of 45
Other than the matching service, the SS&C application states that SS&C will not perform any other functions of a clearing agency requiring registration under Section 17A of the Exchange Act, such as net settlement, maintaining a balance of open positions between buyers and sellers, marking securities to the market, or handling funds or securities.
Section 17A of the Exchange Act directs the Commission to facilitate the establishment of (i) a national system for the prompt and accurate clearance and settlement of securities transactions and (ii) linked or coordinated facilities for clearance and settlement of securities transactions.
Section 17A(b)(1) of the Exchange Act requires all clearing agencies to register with the Commission.
In the Matching Release,
[A]ny person who acts as an intermediary in making payments or deliveries or both in connection with transactions in securities or who provides facilities for comparison of data respecting the terms of settlement of securities transactions, to reduce the number of settlements of securities transactions, or for the allocation of securities settlement responsibilities.
The Commission received thirty comment letters in response to the BSTP and SS&C notices from twenty-three commenters, including two comment letters from BSTP and one from SS&C.
Commenters include individuals and firms representing buy-side and sell-side market participants, in both front and back-office capacities, with expertise in equities and fixed income, asset management, post-trade strategy, and operations. Four of the comment letters were submitted by the Depository Trust and Clearing Corporation (“DTCC”),
For commenters to the BSTP application expressing support more generally for competition in the provision of matching services, see Ambos, Durant, and Naratil.
The discussion below first summarizes DTCC's proposed model for access to DTC submitted as part of its comments regarding the BSTP and SS&C applications. The discussion next provides an overview of comments organized by the particular subject matter raised across the respective comment files, and provides BSTP's and SS&C's responses as well as the Commission's assessment and response within each subject matter section. The Commission notes here that many of DTCC's current arguments are inconsistent with prior representations it made when it sought for Omgeo—and Omgeo was granted, based on those representations—an exemption from registration to provide matching services. Those representations are discussed in detail below.
In order to evaluate many of the particular issues raised by the commenters, the Commission first generally notes DTCC's proposal for structuring access to DTC, which is referenced throughout the Commission's consideration of comments below. According to DTCC, the optimal access model, referred to below as the “single access” model, would enable the industry to continue to rely on the existing systems (including certain systems currently located in Omgeo) to serve as the unique point of access to what DTCC describes as “the existing infrastructure,” in particular DTC and the bank and broker-dealer custodians/settlement agents for the sending of matching confirmations and settlement instructions.
DTCC believes that this approach would promote the safe and efficient clearance and settlement of securities transactions while permitting the securities industry to reap the benefits of the reliable, centralized infrastructure that has developed over the past forty years.
The Commission evaluates the merits of the BSTP and SS&C applications on their own terms under the statutory standard described above. The Commission is not opining on the general issue of whether a multiple access model is always preferable to a single access model.
Under Section 17A of the Exchange Act, Congress directs the Commission to facilitate a prompt system for clearing and settling transactions, and the Congressional findings in Section 17A state that inefficient procedures for clearance and settlement impose unnecessary costs on investors and persons facilitating transactions.
The Commission received multiple comments addressing whether the expected effect of the BSTP and SS&C applications would result in various inefficiencies, with a particular focus on the possibility of unnecessary costs and processing inefficiencies. BSTP states in its comment letter that the BSTP application promotes processing efficiencies by proposing to bring automation to some segments of the marketplace that today use manual procedures and by enabling straight-through processing throughout the entire trade lifecycle, which BSTP states will contribute to increases in same-day affirmation rates and increases in settlement rates.
However, DTCC raises multiple concerns, summarized below, about the effect of the applications on the efficiency (both in terms of unnecessary costs and processing inefficiencies) of the settlement system for U.S. equities. The Commission understands that DTCC is primarily concerned with the following matters: (i) whether it is efficient for BSTP and SS&C to have direct access (rather than mediated access) to DTC for submission of delivery orders; (ii) whether new matching service providers might negatively affect current trade confirmation/affirmation rates; (iii) how control numbers for trades can be managed efficiently in a marketplace with multiple matching service providers; and (iv) whether the costs that DTCC and market participants might incur to incorporate new matching service providers into the market infrastructure can be supported by the anticipated benefits. The Commission evaluates each of these concerns in turn.
With respect to the access model proposed by each of the BSTP and SS&C applications, DTCC states that allowing both BSTP and SS&C to access DTC directly under a “multiple access” model would impose additional costs on the industry, including the cost of building access to DTC for each applicant and the related cost of building parallel access to custodians and settlement agents.
DTCC's current arguments supporting a single access model that runs through Omgeo cannot be reconciled with DTCC's own prior representations surrounding the formation of the joint venture between DTCC and Thomson Financial (Global Joint Venture or “GJV,” later renamed Omgeo), which was granted an exemption from registration to provide matching services in the Omgeo order.
For purposes of background, as a condition precedent to the GJV's formation, DTC submitted a proposed rule change to transfer DTC's existing ETC and matching engine to Omgeo as its contribution to the GJV.
In the above proposed rule change, the transfer involved TradeMessage (automated exchange of messages such as block trade notices of execution, allocation instructions, trade confirmations, and affirmations), TradeMatch (electronic comparison of investment manager allocations with broker-dealer trade confirmations), TradeSettle (supplier of account and settlement data using DTC's Standing Instructions Database, and router of settlement instructions to custodian banks and clearing agents), and TradeHub (router of messages).
The Commission believes that providing a summary of key comments on the DTC 00-10 proposal is helpful in explaining the Commission's assessment of DTCC's objections to the BSTP and SS&C applications because the past comments raise many of the same issues raised in the comments to this order. One of the commenters cited by the Commission in the DTC 00-10 approval order, TradingLinx, focused its concern on the transfer of TradeMessage and TradeSettle,
Another commenter on the DTC 00-10 proposal, GSTP AG, expressed concerns that combining elements of DTC with a commercial entity could result in denial of access to DTC for matching service competitors, and/or pricing for access to DTC settlement and depository services that might preference GJV over matching service competitors.
DTCC's subsequent response indicated that DTC would limit its activities to following the settlement instructions authorized by its participants, whether those instructions were submitted by GJV or GSTP AG.
Subsequent to approval of the Omgeo order, DTC also submitted proposed rule change SR-DTC-2001-11, proposing to authorize DTC to accept and act upon instructions provided by a central matching provider other than Omgeo. The Commission's approval order discussed two significant factors relevant to DTCC's comments regarding access to DTC.
In approving the proposed rule change, the Commission stated its belief that the DTC rule change was consistent with the Exchange Act because it would allow DTC to act upon deliver order instructions received from a matching service provider.
Even apart from DTCC's prior inconsistent representations, the Commission is also unpersuaded that the prospect of incurred costs merits denial or modification of the applications insofar as they propose a multiple access model. Matching service providers cannot settle transactions since they necessarily require access to the central securities depository for the United States, and as such access to the central securities depository is distinct from access to other post-trade processes (such as providing a standing instructions database).
The Commission notes that the BSTP and SS&C applications did not specify whether BSTP or SS&C planned to develop their own duplicate standing instructions database. In cases where BSTP and SS&C can choose whether to depend on an existing system or develop their own, the Commission expects that market forces will determine whether utilizing existing services or systems will be dictated by an assessment of the business costs and benefits related to such choices. The Commission believes that such decisions are not predetermined.
Finally, the Commission notes that DTCC has adopted a multiple access model for trade data submitted to one of its other registered clearing agencies, NSCC. Currently, NSCC receives trade data directly from exchanges, qualified special representatives, correspondent clearing agencies, and Omgeo.
DTCC states that the multiple access model contemplated by the BSTP and SS&C applications may decrease the promptness of the current matching services infrastructure by increasing the time necessary to route confirmations and affirmations between customers and service providers.
BSTP requested that the Commission clarify the need for a matching service provider to obtain no-action relief under Rule 10b-10 in order to provide ETC and matching services. The Commission notes that BSTP has obtained such no-action relief from the Division of Trading and Markets. In addition, the Commission notes that SS&C obtained no-action relief from the Division of Trading and Markets in 2008.
After carefully considering these comments, the Commission believes that, on balance, approval of the BSTP and SS&C applications is more likely to promote rather than impair promptness in the market for matching services, particularly with respect to the effect on confirmation/affirmation rates and industry efforts to shorten the settlement cycle. First, the Commission acknowledges that obtaining access to new matching service providers may require market participants to modify existing systems or purchase new systems to facilitate access to those matching service providers. But the Commission notes that these costs would be borne only by market participants presented with new products or services that they anticipate will offer benefits not available via the existing market infrastructure or via existing matching service providers that justify bearing these costs. DTCC's concern that these systems may be duplicative ignores that duplicative services may carry benefits that market participants seek, such as providing a new access point to DTC, a new interface with features not provided by Omgeo, or access to new markets or market participants not accessible through Omgeo.
BSTP states that its matching service will receive trade execution information in real time, thereby enabling users to immediately identify and address processing exceptions on the trade date. BSTP states that it will provide a variety of efficiency tools that it believes are not currently offered to market participants to help them manage settlement exceptions, including tools for exception monitoring and instant chat functionality.
Second, the Commission does not find DTCC's argument that matching services fall among those components of the market's infrastructure having characteristics where the optimal structure is to provide them via a single entity rather than multiple competing firms to be so compelling as to justify denial or modification of the applications. DTCC comments, including comments in the Cornerstone Report, fail to establish or otherwise substantiate in any specific detail how the fixed costs of operating a matching service are so high as to generate inefficiencies if borne by more than one provider.
DTCC also suggests that access to multiple matching service providers may increase the time necessary to route confirmations and affirmations between customers and service providers, which may interfere with market participants' ability to satisfy their obligations under Regulation SHO. DTCC also states that duplication of systems may result in multiple providers of Rule 10b-10 confirmations, resulting in unnecessary duplicate systems, additional costs, and an increased risk of errors.
In response to DTCC, BSTP counters that Omgeo actually impedes the move to a shortened settlement cycle by reducing the incentives for new providers to enter the market and thereby attract market participants to use matching services. BSTP states that it intends to service, among others, investment managers, brokers, and custodians that currently rely on manual processes for post-trade matching of trade and allocation information. In particular, BSTP states that it will enable such investment managers to gain the benefits of an electronic matching service while continuing to use their existing workflows (fax, email, PDF, etc.) to send allocation instructions to their executing brokers, an important segment of market participants necessary to shorten the settlement cycle.
Related to DTCC's concerns regarding efficient access to DTC, DTCC also raises concerns about how, under a multiple access model, control numbers
The Commission agrees that there are potential benefits to centralizing trade data in a single repository. Indeed, BSTP states that the creation of the control number, the transmission of the control number to the parties involved in settlement, and the transmission of settlement instructions to DTC are critical components of post-trade processing, and, as such, are elements of the national clearance and settlement system that ought to be provided on a fair and non-discriminatory basis by DTC.
DTC rule change SR-DTC-2001-11 was approved to allow DTC to accept and act upon instructions provided by a matching service provider, and if centralization of trade data is necessary for such settlement, DTC has undertaken, in its capacity as a registered clearing agency and SRO, to perform such services.
DTCC states that both the DTCC complex and market participants would face increased costs if the multiple access model contemplated by the BSTP and SS&C applications were implemented, and that the risks and costs of building and testing these connections would multiply exponentially as additional matching service providers enter the market.
With respect to the implementation of new network designs and interfaces, and the provision of access, the Commission is unpersuaded that the prospect of additional expenses merits denial or modification of the applications. The Commission acknowledges that the entry of BSTP and SS&C into the market for matching services may initially result in additional investments by BSTP, SS&C, Omgeo, and DTC, as well as potentially a number of other market participants who rely upon such entities in various capacities. Neither DTCC nor any of those entities quantified the associated costs, however. The Commission expects that, as for-profit entities, neither BSTP nor SS&C would choose to bear these costs, including costs passed through from DTC, unless either believed it could do so profitably. While there may be initial costs required to establish new linkages, these new linkages will introduce competition and choice into the market for matching services, providing new opportunities for innovation that may reduce costs to market participants in the long run, as discussed further below. Indeed, there was unanimity in the comments by market participants about the impact on costs passed down to them: twenty-three market participants or industry groups commented on the BSTP application and expressed no concerns about costs being passed on to them. Rather, as noted previously, many of the commenters stated the opposite—that the introduction of new matching service providers would reduce costs to industry.
With respect to implementation difficulties, the Commission is unpersuaded that the prospect of expenditures merits denial or modification of the applications. As previously discussed, both Omgeo and DTC agreed to a number of conditions that anticipated, and were designed to facilitate, the possibility of new matching service providers.
Section 17A of the Exchange Act directs the Commission, in facilitating the establishment of the national clearance and settlement system, to have due regard for, among other things, maintenance of fair competition among clearing agencies.
One commenter states explicitly that approving the BSTP application would be consistent with the objectives of Section 17A of the Exchange Act and investor protection by promoting the integrity of the financial markets.
There was unanimous support for new entrants to provide matching services. Several commenters anticipated that additional providers of matching services would yield benefits, namely increases in competition, choice, and innovation within the market for matching services.
Despite general agreement on the benefit of competition among matching service providers, DTCC and the applicants disagreed on the specific terms under which new entrants would compete with Omgeo, the only current matching service provider. DTCC states that the conditions on access and pricing in the BSTP and SS&C notices should be reconsidered. While noting that the conditions are substantially the same as those imposed on Omgeo, DTCC offers several bases for modification: Changes in the marketplace (including DTCC's 2013 purchase of Thomson Financial's outstanding ownership interest in Omgeo), differences in the ownership and governance of Omgeo and the applicants, differences in the related services offered by applicants' affiliates, differences in the pricing structures of Omgeo and the applicants, and changes in law and regulation since 2001.
In response to DTCC's comments above, SS&C comments that it is not for DTCC to determine the affordability of its offering but rather for the marketplace to decide. SS&C states that it is fully committed to honoring the pricing and access conditions set forth in the SS&C application and notice. SS&C also notes that while Omgeo may not compete for customers in the United States, it does in other jurisdictions, including Canada, where Omgeo and SS&C are already direct competitors.
DTCC also raises several competition concerns specific to the BSTP application. First, DTCC questions whether BSTP might bundle its matching service with other BLP services, raising potential antitrust concerns by creating a disincentive for BLP customers to use Omgeo's matching service. DTCC states that BLP should clarify its intentions with regard to
In response to the multiple comments summarized above, BSTP comments that DTCC's assertion of potential antitrust concerns has no merit and that DTCC does not offer any logical explanation of how approving the BSTP application, and thereby introducing Omgeo's first competitor, could harm competition, but notes that it may affect Omgeo's current monopoly and DTCC's own business interests.
Lastly, DTCC states that the Commission should require conditions on access to BSTP's FailStation product that are similar to those required for Omgeo's ALERT service and contained in the Omgeo order. DTCC cites BSTP's own description of FailStation as an industry utility that aggregates failed trade and settlement pre-matching data from all trade counterparties in real time into a single report for the investment manager, custodian, and broker. DTCC draws parallels between access to FailStation and access to ALERT, noting that commenters expressed concerns about access to ALERT after the creation of Omgeo, and the conditions were included to provide assurances that other central matching services and persons that represent or otherwise provide services to customers (
Because of the interconnected nature of DTCC's many concerns raised above regarding the appropriateness of the access and pricing conditions contained in the BSTP and SS&C notices, the Commission will address them together. With respect to the absence of access and pricing conditions within the BSTP and SS&C applications reflective of their role in the marketplace, the Commission is unpersuaded that the prospect of bundling services, cross-subsidization of services, profitability, restrictions on access to unrelated services, and other like concerns merits denial or modification of the applications. To clarify, the Commission disagrees with DTCC's characterization of the historical purpose of these conditions under the Omgeo order as being tied to any particular applicant's ownership model or any particular marketplace structure.
The Commission also disagrees with DTCC's attempts to draw a parallel between the role that DTC and associated settlement system products (such as ALERT) play in the national clearance and settlement system and the role that Bloomberg Terminals, FailStation, and other BLP products play in the national clearance and settlement system. Despite any promotional claims that such products are industry utilities, from a regulatory perspective, Bloomberg Terminals, FailStation, and other BLP products primarily provide functionality for executing trades rather than clearing and settling trades. DTC, in contrast, as a registered clearing agency and the CSD for U.S. equities, is a critical element of the national system for clearance and settlement. In addition, the arguments presented by DTCC raising concerns over the potential for BSTP to bundle are speculative and the Commission believes that allowing market forces to determine whether bundling, Bloomberg Terminals access, or any other factor influences either high- or low-volume customer choice to be appropriate at this juncture.
With respect to modifying the conditions as applied to SS&C and BSTP, the Commission believes that market conditions continue to support consistent treatment across matching service providers. The Commission believes that a potential overlap in targeted customer bases between the
With respect to innovation, both BSTP and SS&C state that their applications will promote new data processing techniques and technology-driven solutions. For example, SS&C states that its service stands out in terms of its flexibility,
On balance, the Commission believes that the access and pricing conditions in the BSTP and SS&C notices would promote fair competition. New entrants such as BSTP and SS&C could foster competition in the provision of matching services by competing with Omgeo by reducing the cost of matching services to broker-dealers and institutional customers or increasing the quality or type of services offered. Competition, in turn, could foster innovation in the market for matching services, resulting in more efficient matching and communications systems.
Competition, choice, and innovation are not only addressed by commenters in the context of the general prospect of new entrants BSTP and SS&C, but also within the context of the discussion raised by DTCC regarding BSTP and SS&C's multiple access model workflow and DTCC's alternative single access model workflow. DTCC states that the Commission should distinguish competition in central matching from competition in access to settlement and related functions (
In response, BSTP states that using Omgeo, as DTCC proposes, creates an unjustified barrier to entry, discouraging vendors from entering the matching services business because of the limited scope of services they would be able to provide outside Omgeo and because a competitor, Omgeo, would continue to control certain basic matching services functions. For example, BSTP states that such a workflow would place a competitor between the matching service provider and DTC, and between the matching service provider and custodians and settlement agents.
BSTP states that direct access to DTC is essential to the matching services concept and critical to the national system for clearance and settlement. BSTP states that DTCC's recommendation for a single-access model draws a fundamentally incorrect and inappropriate dichotomy by highlighting the distinction between matching services and access to settlement functions because it suggests that a matching service consists only of the internal function of comparing data and not the function of transmitting an affirmed confirmation to DTC. BSTP notes that previous Commission statements have clarified that a matching service seeking an exemption from registration as a clearing agency would be required to establish an electronic link to a registered clearing agency that provides for the settlement of its matched trades.
BSTP also states that mandating the use of Omgeo would be inconsistent with DTC's obligations as a registered clearing agency. Citing Section 17A(b)(3)(F) and (I) of the Exchange Act, BSTP states that DTC has an obligation to maintain rules that foster cooperation and coordination with persons engaged in the clearance and settlement of securities transactions, that remove impediments to and perfect the mechanism of a national system for the prompt and accurate clearance and settlement of securities transactions, and that do not impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Exchange Act. BSTP states that mandating the use of Omgeo would be inconsistent with these obligations because DTCC would have the Commission adopt a requirement that favors one or more of DTCC's wholly-owned subsidiaries when Section 17A imposes an affirmative obligation to facilitate the development of matching services in a manner that
BSTP notes that access to DTC was a major concern when the Commission issued the Omgeo order, and the Commission has above already assessed DTC's arguments regarding efficient access to DTC against the historical background to the Omgeo order and related DTC rule filings.
Further, BSTP states that mandating the use of Omgeo would require DTC to propose an unjustifiable rule change. BSTP notes that, as a registered clearing agency, DTC is a rules-based organization, and BSTP further notes that DTCC has cited to no rule that would require matching services to use Omgeo to access DTC. BSTP states that, if DTC wished to adopt such a requirement, it would be required to submit a proposed rule change, subject to notice, public comment, and Commission review and approval. BSTP notes that DTC has not submitted such a proposed rule change and further notes its belief that any such proposed rule change would be unsupportable under the Exchange Act.
SS&C states in its letter that it is in complete agreement with BSTP's response on matters where the concerns raised by DTCC are substantially the same between the BSTP and SS&C applications, including the single versus multiple access question.
The Commission is unpersuaded that, in considering the prospect of competition among matching service providers, it must find that a single, direct link to DTC through Omgeo is the only outcome sufficient to support approval of the BSTP and SS&C applications. As discussed previously, the Commission has already approved DTC rule change SR-DTC-2001-11, which authorized DTC to accept from a matching service provider a file of deliver order instructions to settle transactions between DTC participants that have authorized DTC to accept such instructions from the matching service provider.
Further, the Commission is unpersuaded that it should deviate from this existing regulatory framework because of DTCC's proposed vision for how competition among matching service providers could work. As discussed above, the Commission notes that it has previously described its expectation that an entity seeking an exemption as a matching service provider would be required to establish an electronic link to a registered clearing agency that provides for the settlement of its matched trades.
Within the concept of requiring linked or coordinated facilities for clearance and settlement of securities transactions is the implication that any one facility that is connected to other facilities could generate externalities that can affect the system as a whole. If such externalities can create disruptions to the national system for clearance and settlement, then the prospect of such systemic risk implicates facilitating the establishment of linked or coordinated systems.
The Commission received multiple comments addressing the expected effect of the BSTP and SS&C applications on systemic risk. BSTP notes in its comment letter that the BSTP application promotes investor protection by providing a prompt and accurate matching service that eliminates a single point of dependency in the current market infrastructure for matching services, thus enhancing the robustness of the clearance and settlement system.
Multiple commenters agree with BSTP and SS&C. Ten commenters note that increasing the number of matching service providers would remove the single point of dependency present in the existing market infrastructure for matching services, decreasing the risks associated with a single point of failure.
In its comment letters and in the Cornerstone Report, however, DTCC raises multiple concerns about the effect of the applications on systemic risk. Central to the disagreement between the applicants and DTCC is whether BSTP and SS&C should have direct access to DTC. Further, to the extent that BSTP and SS&C have direct access to DTC, DTCC states that such linkage arrangements may increase systemic risk to the market's settlement infrastructure. DTCC also disagrees with commenters stating that the BSTP and SS&C applications will alleviate the single point of dependency problem that exists in the current market infrastructure, stating that a single market participant is unlikely to subscribe to two separate matching service providers and therefore not increase the resiliency that results from redundant systems.
First, BSTP states that Omgeo represents a single point of failure for matching services because it is the only means of accessing DTC for settlement.
DTCC counters that allowing both BSTP and SS&C to access DTC directly would increase systemic risk relative to a single access model because a single access model has fewer interfaces within the market infrastructure that provides matching services, meaning fewer potential points of failure, less complexity, and therefore less risk to the national clearance and settlement system.
The Commission notes that it has already addressed several arguments related to efficiency concerns regarding access to DTC in Part III.B.2.i. On the single point of dependency question, the Commission agrees with BSTP and disagrees with DTCC. As DTCC correctly notes, the risk that the clearance and settlement system would fail during times of market stress, such as the 1987 market break, has been described as the single most important threat to the U.S. financial system, and that settlement failures, if widespread, can have a systemic impact on the national clearance and settlement system while imposing significant costs on market participants.
The Commission acknowledges, as noted by DTCC, that in order for one matching service provider to facilitate redundant access to DTC in the event Omgeo or another matching service provider experiences a disruption, customers will need to have access to multiple matching service providers. The Commission notes that, unlike participants in a CCP, customers of a matching service provider are not subject to requirements to determine suitability for membership. Because obtaining access to a matching service provider is not subject to determinations regarding suitability for membership, the Commission expects that customers could gain access to a secondary matching service provider with enough
With respect to the direct links proposed by the BSTP and SS&C applications, the Commission is unpersuaded that the prospect of increased technical complexity merits denial or modification of the applications. As BSTP notes in its comment letter, technological improvements since approval of the Omgeo order have increased the ability to establish safe and secure communication links.
The Commission acknowledges that there may be externalities associated with a settlement infrastructure where multiple competing matching services link to DTC. Such externalities could manifest if, for example, a systems failure at BSTP reduces the ability of DTC to process transaction information received from Omgeo or SS&C. In such a scenario, BSTP may not fully internalize the costs of errors in its systems because a portion of these costs are imposed on its competitors. The Commission believes, however, that the interoperability conditions, along with the requirements in Regulation SCI for SCI entities to coordinate the testing of business continuity and disaster recovery plans on an industry-wide basis,
In addition, DTCC notes two other benefits of its single-access model: (i) DTC would receive earlier warnings of potential problem transactions, which would reduce disruptions and improve the reliability and efficiency of the national clearance and settlement system; and (ii) exclusive reliance on Omgeo for access to DTC, NSCC, and the custodians/settlement agents would permit DTCC to facilitate future developments in the operational systems used to generate trade instructions for clearance and settlement, thereby reducing risk of system disruptions or system incompatibilities that result in trade failures.
Second, DTCC states it is essential that only one entity issue control numbers because multiple issuers of control numbers would greatly increase the likelihood of settlement errors.
BSTP acknowledges that, ideally, there should be one issuer of control numbers and that, because it is essential to the safe and sound settlement of securities transactions, it is the responsibility of DTC to provide control numbers as a registered clearing agency.
BSTP explains that, contrary to DTCC's claim that a specific time for obtaining a control number should be incorporated into BSTP's application, incorporating a control number in the matching process is well understood. BSTP cites the Matching Release in explaining that the control number is obtained from DTC during the process of confirming the terms of a trade with the broker-dealer involved in the trade.
The Commission has previously addressed the concerns regarding issuance and management of control numbers above in Part III.B.2.iii, including DTCC's concerns regarding centralization of trade data. The Commission does not view the prospect of a multiple access model as being inconsistent with the ability to have a centralized source of control numbers. Consequently, the Commission finds the systemic risk concerns cited by DTCC on this matter to be unpersuasive.
Lastly, the Cornerstone Report raises concerns that, because of the potential increase in systemic risk resulting from the approval of multiple matching service providers, market participants' ability to comply with Regulation SCI may be impaired.
DTCC raises concerns about how the sudden insolvency of either BSTP or SS&C might raise systemic risk concerns in the event that market participants, who had come to rely on the availability of BSTP and SS&C as matching service providers, were no longer able to use their matching services.
BSTP responds that it has devoted substantial resources to developing its matching service, is committed to that matching service, and is adequately capitalized. In addition, BSTP states that, as part of obtaining an exemption from registration as a clearing agency, BSTP has agreed to provide the Commission annual audited financial statements, and states that no additional assurances regarding financial strength should be necessary.
With respect to the future potential insolvency of the applicants, their parents, and their affiliates, the Commission believes such speculation does not merit denial or modification of the applications at this time. DTCC provides no rationale for why, as for-profit entities, BSTP and SS&C, or their parent companies or affiliates, are more likely to become insolvent than Omgeo or DTCC. Indeed, the Commission notes that DTCC's own Cornerstone Report suggests that, in a market with multiple matching service providers, Omgeo may find itself no longer financially viable.
Further, the Commission is mindful that, during an extended service outage, the failure of a single matching service provider could cause significant disruption to the financial markets. In this regard, denying the BSTP and SS&C applications would preserve such risk and leave it concentrated in a single entity because Omgeo is currently the only matching service provider for the U.S. equity markets. The Commission believes that approving the BSTP and SS&C applications could help mitigate this risk.
DTCC expressed concerns regarding whether BSTP and SS&C systems would have the capacity to handle the significant amount of potential order flow, particularly during the high volumes that can occur during times of market stress or volatility, noting that Omgeo has developed with its customers both direct proprietary links to existing systems as well as web-based linkages and interfaces hosted by third party order management systems and
The Commission is satisfied that both the BSTP and SS&C applications provide sufficient assurances regarding their proposed risk management framework. First, as SS&C notes in its comment letter, SS&C Canada and SSCNet have represented that they are staffed adequately with qualified and experienced industry veterans that have been in the post-trade services industry for decades and notes that it has long advocated for responsible growth when it comes to staffing numbers, facilities, and infrastructure. SS&C also represented that it has consistently applied stress and capacity disciplines during its history to ensure the soundness of its post-trade application.
The Commission discusses concerns specific to BSTP and SS&C's operational risk management frameworks below in Part III.B.5. Concerns raised by DTCC in response to the cross-border nature of the SS&C application are addressed in Part III.B.5.i below as well.
DTCC notes that the SS&C application represents that SS&C will only match up to one percent of the U.S. aggregate daily volume of securities trades and would seek an amendment 180 days prior to exceeding that limit, which means that SS&C may have to refuse to provide matching services to some trades in some instances, which may create problems for market participants that are uncertain whether their trades would be accepted for matching by SS&C.
Under Section 17A of the Exchange Act, applicants must demonstrate that they are so organized and have the capacity to be able to facilitate the prompt and accurate clearance and settlement of securities transactions. Questions of capacity have previously been addressed in Parts III.B.2.ii, in connection with facilitating access to DTC, and III.B.4.iii, in connection with questions about the applicants' resiliency. Nevertheless, several comments raised concerns related to particular operational risks, and the Commission considers such concerns below.
With respect to operational risk management, DTCC notes that its own regulated affiliates have each been subject to business continuity standards higher than those set forth in Regulation SCI.
BSTP responds that it is staffed with an adequate number of qualified and experienced personnel to operate BSTP. BSTP notes that its staff includes industry veterans who know the marketplace and are well suited to operate BSTP and ensure that BSTP complies with all applicable regulatory standards, including stringent business continuity, information security, and capacity testing plans and procedures.
SS&C responds that, if granted an exemption, all parts of the SSCNet matching service would be subject to Regulation SCI. SS&C states that there is no legal basis for Regulation SCI to apply to the broader SS&C complex, however, because those affiliates and subsidiaries are not within the scope of entities subject to Regulation SCI under the conditions proposed in the SS&C notice. SS&C further states that SSCNet will be subject to and intends to comply with all of the standards specified by the Commission that are applicable to exempt clearing agencies.
The Commission addresses concerns specific to the cross-border nature of SS&C's operations below. More generally, the Commission notes that there has been a long history of parent and affiliate companies providing facilities management and operational support for clearing entities, and this has been accepted by the Commission in the past. For example, in 1972 the New York Stock Exchange and Amex founded the Securities Industry Automation Corporation (“SAIC”) to handle such services for their clearinghouses.
Further, as noted elsewhere in this order,
DTCC states that BLP's historic treatment of intellectual property raises concerns regarding BSTP's safeguards in this area, as well as in maintaining the privacy of users and the confidentiality of data within its databases. DTCC notes that BSTP plans to license its software, hardware, administrative, operational, and other support services from BLP, and therefore stated that the Commission should require extensive firewalls and other internal controls to prevent the misuse of clearing data obtained through BSTP's ETC and matching service.
The Commission has evaluated the aspects of the BSTP application relating to operational risk management and internal controls. DTCC's arguments made about the prospect of confidentiality or privacy breaches are speculative and unsubstantiated by any past conduct or previous violations. The BSTP application indicates that BSTP has planned for adequate systems capacity and that it conducts stress testing. The Commission notes that BSTP and its affiliates have a business continuity management program to ensure a timely response to, and effective recovery from, unanticipated business interruptions that may affect facilities, technology, and/or people. The Commission also notes that the BSTP application indicates BSTP staff includes industry veterans knowledgeable of the marketplace and well suited to operate BSTP.
As with BSTP, the Commission has reviewed the staffing, reliance on affiliates for operational systems, internal controls, and related aspects of the SS&C application. Again, DTCC's arguments made about the prospect of confidentiality or privacy breaches are speculative and unsubstantiated by any past conduct or previous violations, and SS&C has been providing local and centralized matching facilities and ETC services for twenty years.
In addition, as discussed above, BSTP and SS&C, as SCI entities, will be subject to Regulation SCI. For example, Rule 1001(b) of Regulation SCI requires an SCI entity to have policies and procedures reasonably designed to ensure that their SCI systems operate in a manner that complies with the Exchange Act and rule and regulations thereunder and the entity's rules and governing documents, as applicable.
DTCC notes that the SS&C application indicates all matching service activities will be performed by SS&C Canada. DTCC states that SS&C's reliance on a foreign subsidiary to perform critical functions distinguishes the SS&C application from the circumstances underlying, and the regulatory impact of, Omgeo's current exempt status, and raises concerns for the safety and soundness of the national clearance and settlement system.
On a general level, DTCC states that the Commission must satisfy itself of the following: (i) that the role of SS&C Canada would not weaken the regulatory framework applicable to SS&C's activities; and (ii) that the proposed framework in which SS&C is the regulated entity but SS&C Canada performs the actual matching function would not create a risk of disconnectedness or regulatory impairment with respect to the Commission's oversight of the national clearance and settlement system. In addition, DTCC states that the Commission should carefully scrutinize SS&C's undertakings with respect to operational, interoperability, and access matters, and its own ability to monitor the effects of SS&C's overall activities on the national system for clearance and settlement.
On a more specific level, DTCC states several concerns relating to choice of law, jurisdiction, privacy of information, and timely access to records.
Further, DTCC states that it understands that certain activities of SS&C Canada are regulated by the Ontario Securities Commission (“OSC”) and the Autorité des marchés financiers (“AMF”), and therefore SS&C should demonstrate that its reliance on SS&C Canada for the purposes contemplated in the SS&C application are not in conflict or inconsistent with existing requirements under applicable Canadian provincial securities laws.
In addition, DTCC states that the SS&C application does not discuss any due diligence performed by SS&C with respect to SS&C Canada and SS&C Canada's capabilities in supporting SS&C or its abilities to discharge the services and obligations contemplated in the intercompany agreement.
Finally, DTCC notes that, pursuant to the SS&C application, SS&C Canada will operate the matching and ETC service on behalf of SS&C. DTCC believes operational support may be provided to an exempt clearing agency by a non-U.S. affiliate but states that the SS&C application raises issues related to such support. DTCC states, for example, that pursuant to its application, the policies and procedures of SS&C Canada are overseen by its officers and directors and subject to control by SS&C Holdings. DTCC believes that SS&C Canada's policies and operations related to matching should be overseen by SS&C itself.
DTCC notes, in particular, the integral role played by SS&C Canada suggests that extra scrutiny be placed on cross-border issues to the extent they could delay or impede the proper functionality of trade matching and settlement, as previously noted above.
SS&C responds that the various assertions described above regarding the oversight of SS&C Canada by SS&C are unfounded and that SS&C has complete oversight of and visibility into the operations of SSCNet. SS&C further states that SS&C Canada and the SSCNet application fall under the scrutiny and review of a number of SS&C's U.S.-based executive committees providing direct oversight, including its Operating Committee, its Security Committee, and a U.S.-based internal audit department that reports to the U.S.-based Audit Committee. It also states that the SSCNet division reports to the U.S.-based Senior Vice President, Institutional and Investment Management; its development division reports to the U.S.-based Senior Vice President, Chief Development Officer; and its Information Technology Services division reports to the U.S.-based Chief Technology Officer. SS&C also notes that Omgeo operates in many
SS&C also responds that DTCC incorrectly asserts that some or all applications offered by SS&C are comingled with each other and that intellectual property, privacy of users, and confidentiality of data is lacking. SS&C states that it is a leading global data service provider that deploys information security policies, procedures, and controls that meet or exceed industry standards and that SS&C has never experienced a breach of security or privacy.
The Commission is satisfied that the cross-border aspects of the SS&C application have been sufficiently addressed without requiring denial or modification of the application. First, as described in Part II.B, the SS&C application includes a series of representations designed to ensure that the Commission can fulfill its regulatory obligations with respect to SS&C. SS&C is a U.S. person incorporated in Delaware with a Connecticut business registration that dates back to 1996. According to its application, SS&C will enter into an intercompany agreement with SS&C Canada governing the availability of information related to matching services. As a subsidiary of SS&C, SS&C Canada will be subject to the control of its parent company. Further, as described in the SS&C letter, SS&C's executive committees such as the Operating Committee and the Security Committee provide direct oversight of SSCNet.
Second, the Commission has entered into a memorandum of understanding concerning consultation, cooperation, and the exchange of information related to the supervision of cross-border regulated entities with the AMF and the OSC. The MOU notes that it is intended to express each authority's willingness to cooperate with each other in the interest of fulfilling their respective regulatory mandates, particularly in the areas of investor protection, fostering the integrity of and maintaining confidence in the capital markets, and reducing systemic risk.
More generally, as previously discussed, the Commission is familiar with arrangements whereby a registered entity contracts out functions to other entities that may or may not be directly regulated by the Commission, and may or may not be located within the U.S. In the absence of a concrete obstacle—for example, a specific foreign statute blocking access currently in effect, or a history of instances of non-compliance by an entity—DTCC's arguments about cross-border risks depend on purely speculative concerns. For example, such prospects are not grounded in a particular fact pattern identified by DTCC or other commenters, and do not demonstrate that SS&C is hindered in its ability to comply with the conditions below.
Finally, we note that as with the Omgeo order, this order includes provisions for modification if necessary or appropriate in the public interest, the protection of investors, or otherwise in furtherance of the purposes of the Exchange Act.
DTCC states that the composition of BSTP's board of directors as described in the BSTP application raises concerns about the overlap between BSTP and its for-profit parent BLP because only one of the board's four members is an industry representative, which could compromise BSTP's independence from BLP and the extent to which BSTP is capable of playing a neutral role as an industry utility.
According to BSTP, while BSTP's parent, BLP, will provide BSTP with software, hardware, administrative, operational, and other support services, BSTP has established a separate board of directors to oversee its operations and will hold ultimate legal responsibility over its operations.
The Commission is mindful of DTCC's concerns but disagrees. As BSTP notes, DTCC provides no support from the Omgeo order that matching service providers be non-profit entities or that for-profit entities be subject to special controls by virtue of that status.
DTCC additionally states that BSTP should be subject to stricter corporate governance controls similar to those imposed on Omgeo, and that BSTP's board should be required to maintain fair representation of its ETC and matching service customers.
In response to DTCC's suggestion that Omgeo is subject to heightened governance requirements, the Commission believes it is appropriate to highlight several reasons for the various legal and other regulatory requirements to which the entities within the DTCC complex are subject, as follows. First, Omgeo is an exempt clearing agency subject to the terms and conditions of the Omgeo order. Second, DTC, by contrast, is a registered clearing agency subject to the full panoply of clearing agency regulation. Accordingly, when the Commission approved transfer of the TradeSuite ID system from DTC to Omgeo, it highlighted the statutory requirement that DTC provide equitable allocation of dues, fees, and other charges among its participants and refrain from imposing any burden on competition not necessary or appropriate in furtherance of the purposes of Section 17A of the Exchange Act.
Several commenters expressed views on the need for interoperability to ensure that a market structure with multiple matching service providers can facilitate the anticipated benefits described above. Specifically, four commenters emphasized the importance of facilitating interoperability between matching services. Two commenters stated that interoperability is vital to ensure that industry participants may choose their service providers free of any dependency and to support use by the full spectrum of potential users.
The Commission agrees that interoperability among matching service providers is critical to facilitating the establishment of linked and coordinated facilities for the clearance and settlement of securities transactions. In 2001, the Commission issued the Omgeo order mindful of concerns about interoperability. Accordingly, the Omgeo order included interoperability conditions designed to address concerns that, as the sole provider of matching services, Omgeo could improperly gain a monopoly in post-trade processing.
The Commission is satisfied that the BSTP and SS&C applications, which include substantially the same interoperability provisions as those set forth in the Omgeo order, will continue to facilitate these same goals. The Commission notes that both BSTP and SS&C expressed support for interoperability in their comment letters,
DTCC states that the timeframes for building and operating interfaces, as set forth in the Omgeo order and included for BSTP and SS&C as part of this order, do not take into account the amount and complexity of the work that would need to be done to accommodate BSTP and/or SS&C's entry into the market structure for matching services and likely would be insufficient to enable the operational accuracy and reliability for the proper operation of an interface.
DTCC further states that because it does not know the nature of the BSTP and/or SS&C systems, if any, and whether or on what terms BSTP and/or SS&C might be eligible for an exemption from the Commission, it would be unreasonable to expect DTCC to devote resources to such issues until it has sufficient certainty about the nature of the interfaces that would need to be developed, if any.
BSTP responds that there is no justification to delay interoperability of Omgeo with other matching services. BSTP notes that, in the fourteen years since the Commission issued the Omgeo order, neither DTCC nor Omgeo has raised any concerns regarding the terms of that exemption. BSTP notes that the need for DTCC and its subsidiaries to devote resources to comply with the conditions in the Omgeo order is not a valid reason to modify the provisions found in the Omgeo order.
SS&C acknowledges that there could be other appropriate timeframes for building and operating interfaces, and SS&C also states that the interoperability conditions contained within the Omgeo order already provide the means for extending those timeframes. SS&C further states that the conditions proposed in the SS&C notice (the same as those contained in the Omgeo order) provide the appropriate mechanisms to allow parties to extend the timeframes, and accordingly SS&C sees no issue with the conditions proposed in the SS&C notice as they relate to timeframes for building and operating interfaces.
Further, the Commission is mindful that Omgeo, BSTP, and SS&C will need time to develop the appropriate interfaces to ensure that their systems are interoperable consistent with the conditions set forth in the Omgeo order and this order below. The Commission agrees with SS&C that, while other timeframes may also be appropriate to build and operate interfaces, the interoperability conditions provide a mechanism for extending time on which the parties must agree, mitigating the concerns raised by DTCC. Indeed, the conditions help ensure that no one party can unnecessarily delay the process of building and operating interfaces for interoperability. In that regard, to the extent that DTCC was hesitant to devote resources to building and operating interfaces with other matching service providers because of questions as to whether and on what terms BSTP and SS&C would be eligible for an exemption to provide matching services, those questions are fully resolved in this order.
DTCC requests that the Commission clarify whether and to what extent Regulation SCI has superseded reporting requirements for system outages and other events in the Omgeo order. Specifically, DTCC notes that Rule 1003(a) of Regulation SCI requires SCI entities to report material system changes, including submitting to the Commission a report within thirty calendar days after the end of each calendar quarter describing completed, ongoing, and planned material changes to SCI systems and the security of indirect SCI systems.
In addition Rule 1003(a)(2) requires an SCI entity to promptly submit a supplemental report to notify the Commission of a material error in or material omission from a previously submitted report.
On November 19, 2014, the Commission adopted Regulation SCI, which requires SCI entities to comply with requirements for policies and procedures with respect to their automated systems that support the performance of their regulated activities.
In response to DTCC's comment, the Commission notes that operational condition (4) was not a component of the ARP policy statements and therefore has not been superseded by Regulation SCI. Operational condition (4) ensures that the Commission receives 20-days advance notice of systems changes, which the Commission believes is necessary for matching service providers in light of the potential for linkages between matching service providers and the corresponding need for matching service providers to maintain interoperability pursuant to the interoperability conditions of the Omgeo order and this order.
In addition, because Regulation SCI has superseded the requirements in ARP, the Commission is providing clarification as to the requirements in operational conditions (1) and (2), which appear in the Omgeo order and are applied to BSTP and SS&C below.
Pursuant to Rule 1003(b)(2), an SCI entity must submit a report of the SCI review to senior management of the SCI entity for review no more than 30 calendar days after completion of such a review. Moreover, under Rule 1003(b)(3), an SCI entity must submit to the Commission, and to the board of directors of the SCI entity or the equivalent of such board, a report of the SCI review and any response by senior management within 60 calendar days after its submission to senior management.
In evaluating the BSTP application, the Commission has been guided by the requirements of Section 17A of the Exchange Act. Among other factors, the Commission has considered BSTP's risk management procedures, operational capacity and safeguards, organizational structure, and ability to operate in a manner that will satisfy the fundamental goals of Section 17A. The Commission has also carefully considered the comments received in response to the BSTP application, as discussed above. The Commission believes that the BSTP application supports the establishment of linked and coordinated facilities for the clearance and settlement of securities transactions.
Accordingly, for the reasons discussed throughout this order, the Commission finds that the BSTP application, including the terms and conditions set forth in the application and reproduced below, is consistent with the public interest, the protection of investors, and the purposes of Section 17A of the Exchange Act, and that BSTP is so organized and has the capacity to be able to facilitate prompt and accurate matching services.
Below are the terms and conditions of BSTP's exemption.
This order grants BSTP an exemption from registration as a clearing agency under Section 17A of the Exchange Act to provide an ETC and matching service. The exemption is granted subject to conditions that the Commission believes are necessary and appropriate in light of the statutory requirements of Section 17A.
The Commission is including specific conditions to this exemption designed to facilitate the establishment of a national system for the prompt and
(1) Before beginning the commercial operation of its matching service, BSTP shall provide the Commission with an audit report that addresses all the areas discussed in the Commission's Automation Review Policies (“ARP”).
(2) BSTP shall provide the Commission with annual reports and any associated field work prepared by competent, independent audit personnel that are generated in accordance with the annual risk assessment of the areas set forth in the ARP. BSTP shall provide the Commission (beginning in its first year of operation) with annual audited financial statements prepared by competent independent audit personnel.
(3) BSTP shall report all significant systems outages to the Commission. If it appears that the outage may extend for thirty minutes or longer, BSTP shall report the systems outage immediately. If it appears that the outage will be resolved in less than thirty minutes, BSTP shall report the systems outage within a reasonable time after the outage has been resolved.
(4) BSTP shall provide the Commission with 20 business days advance notice of any material changes that BSTP makes to the matching service or ETC service. These changes will not require the Commission's approval before they are implemented.
(5) BSTP shall respond and require its service providers (including BLP) to respond to requests from the Commission for additional information relating to the matching service and ETC service, and provide access to the Commission to conduct on-site inspections of all facilities (including automated systems and systems environment), records, and personnel related to the matching service and the ETC service. The requests for information shall be made and the inspections shall be conducted solely for the purpose of reviewing the matching service's and the ETC service's operations and compliance with the federal securities laws and the terms and conditions in any exemptive order issued by the Commission with respect to BSTP's matching service and the ETC service.
(6) BSTP shall supply the Commission or its designee with periodic reports regarding the affirmation rates for institutional transactions effected by institutional investors that utilize its matching service and ETC service.
(7) BSTP shall preserve a copy or record of all trade details, allocation instructions, central trade matching results, reports and notices sent to customers, service agreements, reports regarding affirmation rates that are sent to the Commission or its designee, and any complaint received from a customer, all of which pertain to the operation of its matching service and ETC service. BSTP shall retain these records for a period of not less than five years, the first two years in an easily accessible place.
(8) BSTP shall not perform any clearing agency function (such as net settlement, maintaining a balance of open positions between buyers and sellers, or marking securities to the market) other than as permitted in an exemption issued by the Commission.
(9) Before beginning the commercial operation of its matching service, BSTP shall provide the Commission with copies of the service agreement between BLP and BSTP and shall notify the Commission of any material changes to the service agreement.
(1) BSTP shall develop, in a timely and efficient manner, fair and reasonable linkages between BSTP's matching service and other matching services that are registered with the Commission or that receive or have received from the Commission an exemption from clearing agency registration that, at a minimum, allow parties to trades that are processed through one or more matching services to communicate through one or more appropriate effective interfaces with other matching services.
(2) BSTP shall devise and develop interfaces with other matching services that enable end-user clients or any service that represents end-user clients to BSTP (“end-user representative”) to gain a single point of access to BSTP and other matching services. Such interfaces must link with each other matching service so that an end-user client of one matching service can communicate with all end-user clients of all matching services, regardless of which matching service completes trade matching prior to settlement.
(3) If any intellectual property proprietary to BSTP is necessary to develop, build, and operate links or interfaces to BSTP's matching service, as described in these conditions, BSTP shall license such intellectual property to other matching services seeking linkage to BSTP on fair and reasonable terms for use in such links or interfaces.
(4) BSTP shall not engage in any activity inconsistent with the purposes of Section 17A(a)(2) of the Exchange Act,
(5) BSTP shall support industry standards in each of the following categories: communication protocols (
(6) BSTP shall make all reasonable efforts to link with each other matching service in a timely and efficient manner, as specified below. Upon written request, BSTP shall negotiate with each other matching service to develop and build an interface that allows the two to link matching services (“interface”). BSTP shall involve neutral industry participants in all negotiations to build or develop interfaces and, to the extent feasible, incorporate input from such
(7) In order to facilitate fair and reasonable linkages between BSTP and other matching services, BSTP shall publish or make available to any other matching service the specifications for any interface and its corresponding commercial rules that are in operation within 20 days of receiving a request for such specifications and commercial rules. Such specifications shall contain all the information necessary to enable any other matching services not already linked to BSTP through an interface to establish a linkage with BSTP through an interface or a substantially similar interface. BSTP shall link to any other matching service, if the other matching service so opts, through an interface substantially similar to any interface and its corresponding commercial rules that BSTP is currently operating. BSTP shall begin operating such substantially similar interface and commercial rules with the other matching service within 90 days of receiving all the information necessary to operate that link. This 90-day period may be extended upon the written agreement of both BSTP and the other matching service that plans to use that link.
(8) BSTP and respective other matching services shall bear their own costs of building and maintaining an interface, unless otherwise negotiated by the parties.
(9) BSTP shall provide to all other matching services and end-user representatives that maintain linkages with BSTP sufficient advance notice of any material changes, updates, or revisions to its interfaces to allow all parties who link to BSTP through affected interfaces to modify their systems as necessary and avoid system downtime, interruption, or system degradation.
(10) BSTP and each other matching service shall negotiate fair and reasonable charges and terms of payment for the use of their interface with respect to the sharing of trade and account information (“interface charges”). In any fee schedule adopted under conditions A.2.ii(10), A.2.ii(11), or A.2.ii(12) herein, BSTP's interface charges shall be equal to the interface charges of the respective other matching service.
(11) If BSTP and the other matching service cannot reach agreement on fair and reasonable interface charges within 60 days of receipt of the written request, BSTP and the other matching service shall submit to binding arbitration under the rules promulgated by the American Arbitration Association. The arbitration panel shall have 60 days to establish a fee schedule. The arbitration panel's establishment of a fee schedule shall be binding on BSTP and the other matching service unless and until the fee schedule is subsequently modified or abrogated by the Commission or BSTP and the other matching service mutually agree to renegotiate.
(12)(A) The following parameters shall be considered in determining fair and reasonable interface charges: (i) The variable cost incurred for forwarding trade and account information to other matching services; (ii) the average cost associated with the development of links to end-users and end-user representatives; and (iii) BSTP's interface charges to other matching services. (B) The following factors shall not be considered in determining fair and reasonable interface charges: (i) The respective cost incurred by BSTP or the other matching service in creating and maintaining interfaces; (ii) the value that BSTP or the other matching service contributes to the relationship; (iii) the opportunity cost associated with the loss of profits to BSTP that may result from competition from other matching services; (iv) the cost of building, maintaining, or upgrading BSTP's matching service; or (v) the cost of building, maintaining, or upgrading value added services to BSTP's matching service. (C) In any event, the interface charges shall not be set at a level that unreasonably deters entry or otherwise diminishes price or non-price competition with BSTP by other matching services.
(13) BSTP shall not charge its customers more for use of its matching service when one or more counterparties are customers of other matching services than BSTP charges its customers for use of its matching service when all counterparties are customers of BSTP. BSTP shall not charge customers any additional amount for forwarding to or receiving trade and account information from other matching services called for under applicable commercial rules.
(14) BSTP shall maintain its quality, capacity, and service levels in the interfaces with other matching services (“matching services linkages”) without bias in performance relative to similar transactions processed completely within BSTP's service. BSTP shall preserve and maintain all raw data and records necessary to prepare reports tabulating separately the processing and response times on a trade-by-trade basis for (A) completing its matching service when all counterparties are customers of BSTP; (B) completing its matching service when one or more counterparties are customers of other matching services; or (C) forwarding trade information to other matching services called for under applicable commercial rules. BSTP shall retain the data and records for a period not less than six years. Sufficient information
(15) BSTP shall process trades or facilitate the processing of trades by other matching services on a first-in-time priority basis. For example, if BSTP receives trade and account information that BSTP is required to forward to other matching services under applicable commercial rules (“pass-through information”) prior to receiving trade and account information from BSTP's customers necessary to provide matching services for a trade in which all parties are customers of BSTP (“intra-hub information”), BSTP shall forward the pass-through information to the designated other matching service prior to processing the intra-hub information. If, on the other hand, the information were to come in the reverse order, BSTP shall process the intra-hub information before forwarding the pass-through information.
(16) BSTP shall sell access to its databases, systems or methodologies for transmitting settlement instructions (including settlement instructions from investment managers, broker-dealers, and custodian banks) and/or transmitting trade and account information to and receiving authorization responses from settlement agents on fair and reasonable terms to other matching services and end-user representatives. Such access shall permit other matching services and end-user representatives to draw information from those databases, systems, and methodologies for transmitting settlement instructions and/or transmitting trade and account information to and receiving authorization responses from settlement agents for use in their own matching services or end-user representatives' services. The links necessary for other matching services and end-user representatives to access BSTP's databases, systems or methodologies for transmitting settlement instructions and/or transmitting trade and account information to and receiving authorization responses from settlement agents will comply with conditions A.2.ii(3), A.2.ii(5), A.2.ii(9), A.2.ii(14) and A.2.ii(15) above.
(17) For the first five years from the date of an exemptive order issued by the Commission with respect to BSTP's matching service, BSTP shall provide the Commission with reports every six months sufficient to document BSTP's adherence to the obligations relating to interfaces set forth in conditions A.2.ii(6) through A.2.ii(13) and A.2.ii(16) above. BSTP shall incorporate into such reports information including but not limited to: (A) All other matching services linked to BSTP; (B) the time, effort, and cost required to establish each link between BSTP and other matching services; (C) any proposed links between BSTP and other matching services as well as the status of such proposed links; (D) any failure or inability to establish such proposed links or fee schedules for interface charges; (E) any written complaint received from other matching services relating to its established or proposed links with BSTP; and (F) if BSTP failed to adhere to any of the obligations relating to interfaces set forth in conditions A.2.ii(6) through A.2.ii(13) and A.2.ii(16) above, its explanation for such failure. The Commission shall treat information submitted in accordance with this condition as confidential, non-public information, subject to the provisions of applicable law. If any other matching service seeks to link with BSTP more than five years after issuance of an exemptive order issued by the Commission with respect to BSTP's matching service, BSTP shall notify the Commission of the other matching service's request to link with BSTP within ten days of receiving such request. In addition, BSTP shall provide reports to the Commission in accordance with this paragraph commencing six months after the initial request for linkage is made until one year after BSTP and the other matching service begin operating their interface. The Commission reserves the right to request reports from BSTP at any time. BSTP shall provide the Commission with such updated reports within thirty days of the Commission's request.
(18) BSTP shall also publish or make available upon request to any end-user representative the necessary specifications, protocols, and architecture of any interface created by BSTP for any end-user representative.
BSTP is required to file with the Commission amendments to its application for exemption on Form CA-1 if it makes any material change affecting its ETC or matching service—as summarized in this order, in its Form CA-1 dated March 15, 2013, or in any subsequently filed amendments to its Form CA-1—that would make such previously provided information incomplete or inaccurate.
In addition, the Commission may modify by order the terms, scope, or conditions of BSTP's exemption from registration as a clearing agency if it determines that such modification is necessary or appropriate in the public interest, the protection of investors, or otherwise in furtherance of the purposes of the Exchange Act. Furthermore, the Commission may limit, suspend, or revoke this exemption if it finds that BSTP has violated or is unable to comply with any of the provisions set forth in this order if such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Exchange Act.
In evaluating the SS&C application, the Commission has been guided by the requirements of Section 17A of the Exchange Act. Among other factors, the Commission has considered SS&C's risk management procedures, operational capacity and safeguards, organizational structure, and ability to operate in a manner that will satisfy the fundamental goals of Section 17A. The Commission has also carefully considered the comments received in response to the SS&C application, as discussed above. The Commission believes that the SS&C application supports the establishment of linked and coordinated facilities for the clearance and settlement of securities transactions.
Accordingly, for the reasons discussed throughout this order, the Commission finds that the SS&C application, including the terms and conditions set forth in the application and reproduced below, is consistent with the public interest, the protection of investors, and the purposes of Section 17A of the Exchange Act, and that SS&C is so organized and has the capacity to be able to facilitate prompt and accurate matching services.
Below are the terms and conditions of SS&C's exemption.
This order grants SS&C an exemption from registration as a clearing agency under Section 17A of the Exchange Act to provide an ETC and matching service. The exemption is granted subject to conditions that the Commission believes are necessary and appropriate in light of the statutory requirements of Section
The Commission is including specific conditions to this exemption designed to facilitate the establishment of a national system for the prompt and accurate clearance and settlement of securities transactions and the establishment of linked and coordinated facilities for the clearance and settlement of securities transactions. The conditions are designed to promote competition, transparency, consistency, and interoperability in the market for matching services.
(1) Before beginning the commercial operation of its matching service, SS&C shall provide the Commission with an audit report that addresses all the areas discussed in the Commission's Automation Review Policies (“ARP”).
(2) SS&C shall provide the Commission with annual reports and any associated field work prepared by competent, independent audit personnel that are generated in accordance with the annual risk assessment of the areas set forth in the ARP. SS&C shall provide the Commission (beginning in its first year of operation) with annual audited financial statements prepared by competent independent audit personnel.
(3) SS&C shall report all significant systems outages to the Commission. If it appears that the outage may extend for thirty minutes or longer, SS&C shall report the systems outage immediately. If it appears that the outage will be resolved in less than thirty minutes, SS&C shall report the systems outage within a reasonable time after the outage has been resolved.
(4) SS&C shall provide the Commission with 20 business days advance notice of any material changes that SS&C makes to the matching service or ETC service. These changes will not require the Commission's approval before they are implemented.
(5) SS&C shall respond and require its service providers to respond to requests from the Commission for additional information relating to the matching service and ETC service, and provide access to the Commission to conduct on-site inspections of all facilities (including automated systems and systems environment), records, and personnel related to the matching service and the ETC service. The requests for information shall be made and the inspections shall be conducted solely for the purpose of reviewing the matching service's and the ETC service's operations and compliance with the federal securities laws and the terms and conditions in any exemptive order issued by the Commission with respect to SS&C's matching service and the ETC service.
(6) SS&C shall supply the Commission or its designee with periodic reports regarding the affirmation rates for institutional transactions effected by institutional investors that utilize its matching service and ETC service.
(7) SS&C shall preserve a copy or record of all trade details, allocation instructions, central trade matching results, reports and notices sent to customers, service agreements, reports regarding affirmation rates that are sent to the Commission or its designee, and any complaint received from a customer, all of which pertain to the operation of its matching service and ETC service. SS&C shall retain these records for a period of not less than five years, the first two years in an easily accessible place.
(8) SS&C shall not perform any clearing agency function (such as net settlement, maintaining a balance of open positions between buyers and sellers, or marking securities to the market) other than as permitted in an exemption issued by the Commission.
(9) Before beginning the commercial operation of its matching service, SS&C shall provide the Commission with copies of the intercompany agreement between SS&C and SS&C Canada and shall notify the Commission of any material changes to the service agreement.
(1) SS&C shall develop, in a timely and efficient manner, fair and reasonable linkages between SS&C's matching service and other matching services that are registered with the Commission or that receive or have received from the Commission an exemption from clearing agency registration that, at a minimum, allow parties to trades that are processed through one or more matching services to communicate through one or more appropriate effective interfaces with other matching services.
(2) SS&C shall devise and develop interfaces with other matching services that enable end-user clients or any service that represents end-user clients to SS&C (“end-user representative”) to gain a single point of access to SS&C and other matching services. Such interfaces must link with each other matching service so that an end-user client of one matching service can communicate with all end-user clients of all matching services, regardless of which matching service completes trade matching prior to settlement.
(3) If any intellectual property proprietary to SS&C is necessary to develop, build, and operate links or interfaces to SS&C's matching service, as described in these conditions, SS&C shall license such intellectual property to other matching services seeking linkage to SS&C on fair and reasonable terms for use in such links or interfaces.
(4) SS&C shall not engage in any activity inconsistent with the purposes of Section 17A(a)(2) of the Exchange Act,
(5) SS&C shall support industry standards in each of the following categories: communication protocols (
(6) SS&C shall make all reasonable efforts to link with each other matching service in a timely and efficient manner, as specified below. Upon written request, SS&C shall negotiate with each other matching service to develop and build an interface that allows the two to link matching services (“interface”). SS&C shall involve neutral industry participants in all negotiations to build or develop interfaces and, to the extent feasible, incorporate input from such participants in determining the specifications and architecture of such interfaces. Absent adequate business or technological justification,
(7) In order to facilitate fair and reasonable linkages between SS&C and other matching services, SS&C shall publish or make available to any other matching service the specifications for any interface and its corresponding commercial rules that are in operation within 20 days of receiving a request for such specifications and commercial rules. Such specifications shall contain all the information necessary to enable any other matching services not already linked to SS&C through an interface to establish a linkage with SS&C through an interface or a substantially similar interface. SS&C shall link to any other matching service, if the other matching service so opts, through an interface substantially similar to any interface and its corresponding commercial rules that SS&C is currently operating. SS&C shall begin operating such substantially similar interface and commercial rules with the other matching service within 90 days of receiving all the information necessary to operate that link. This 90-day period may be extended upon the written agreement of both SS&C and the other matching service that plans to use that link.
(8) SS&C and respective other matching services shall bear their own costs of building and maintaining an interface, unless otherwise negotiated by the parties.
(9) SS&C shall provide to all other matching services and end-user representatives that maintain linkages with SS&C sufficient advance notice of any material changes, updates, or revisions to its interfaces to allow all parties who link to SS&C through affected interfaces to modify their systems as necessary and avoid system downtime, interruption, or system degradation.
(10) SS&C and each other matching service shall negotiate fair and reasonable charges and terms of payment for the use of their interface with respect to the sharing of trade and account information (“interface charges”). In any fee schedule adopted under conditions B.2.ii(10), B.2.ii(11), or B.2.ii(12) herein, SS&C's interface charges shall be equal to the interface charges of the respective other matching service.
(11) If SS&C and the other matching service cannot reach agreement on fair and reasonable interface charges within 60 days of receipt of the written request, SS&C and the other matching service shall submit to binding arbitration under the rules promulgated by the American Arbitration Association. The arbitration panel shall have 60 days to establish a fee schedule. The arbitration panel's establishment of a fee schedule shall be binding on SS&C and the other matching service unless and until the fee schedule is subsequently modified or abrogated by the Commission or SS&C and the other matching service mutually agree to renegotiate.
(12)(A) The following parameters shall be considered in determining fair and reasonable interface charges: (i) The variable cost incurred for forwarding trade and account information to other matching services; (ii) the average cost associated with the development of links to end-users and end-user representatives; and (iii) SS&C's interface charges to other matching services. (B) The following factors shall not be considered in determining fair and reasonable interface charges: (i) The respective cost incurred by SS&C or the other matching service in creating and maintaining interfaces; (ii) the value that SS&C or the other matching service contributes to the relationship; (iii) the opportunity cost associated with the loss of profits to SS&C that may result from competition from other matching services; (iv) the cost of building, maintaining, or upgrading SS&C's matching service; or (v) the cost of building, maintaining, or upgrading value added services to SS&C's matching service. (C) In any event, the interface charges shall not be set at a level that unreasonably deters entry or otherwise diminishes price or non-price competition with SS&C by other matching services.
(13) SS&C shall not charge its customers more for use of its matching service when one or more counterparties are customers of other matching services than SS&C charges its customers for use of its matching service when all counterparties are customers of SS&C. SS&C shall not charge customers any additional amount for forwarding to or receiving trade and account information from other matching
(14) SS&C shall maintain its quality, capacity, and service levels in the interfaces with other matching services (“matching services linkages”) without bias in performance relative to similar transactions processed completely within SS&C's service. SS&C shall preserve and maintain all raw data and records necessary to prepare reports tabulating separately the processing and response times on a trade-by-trade basis for (A) completing its matching service when all counterparties are customers of SS&C; (B) completing its matching service when one or more counterparties are customers of other matching services; or (C) forwarding trade information to other matching services called for under applicable commercial rules. SS&C shall retain the data and records for a period not less than six years. Sufficient information shall be maintained to demonstrate that the requirements of condition B.2.ii(15) below are being met. SS&C and its service providers shall provide the Commission with reports regarding the time it takes SS&C to process trades and forward information under various circumstances within 30 days of the Commission's request for such reports. However, SS&C shall not be responsible for identifying the specific cause of any delay in performing its matching service where the fault for such delay is not attributable to SS&C.
(15) SS&C shall process trades or facilitate the processing of trades by other matching services on a first-in-time priority basis. For example, if SS&C receives trade and account information that SS&C is required to forward to other matching services under applicable commercial rules (“pass-through information”) prior to receiving trade and account information from SS&C's customers necessary to provide matching services for a trade in which all parties are customers of SS&C (“intra-hub information”), SS&C shall forward the pass-through information to the designated other matching service prior to processing the intra-hub information. If, on the other hand, the information were to come in the reverse order, SS&C shall process the intra-hub information before forwarding the pass-through information.
(16) SS&C shall sell access to its databases, systems or methodologies for transmitting settlement instructions (including settlement instructions from investment managers, broker-dealers, and custodian banks) and/or transmitting trade and account information to and receiving authorization responses from settlement agents on fair and reasonable terms to other matching services and end-user representatives. Such access shall permit other matching services and end-user representatives to draw information from those databases, systems, and methodologies for transmitting settlement instructions and/or transmitting trade and account information to and receiving authorization responses from settlement agents for use in their own matching services or end-user representatives' services. The links necessary for other matching services and end-user representatives to access SS&C's databases, systems or methodologies for transmitting settlement instructions and/or transmitting trade and account information to and receiving authorization responses from settlement agents will comply with conditions B.2.ii(3), B.2.ii(5), B.2.ii(9), B.2.ii(14) and B.2.ii(15) above.
(17) For the first five years from the date of an exemptive order issued by the Commission with respect to SS&C's matching service, SS&C shall provide the Commission with reports every six months sufficient to document SS&C's adherence to the obligations relating to interfaces set forth in conditions B.2.ii(6) through B.2.ii(13) and B.2.ii(16) above. SS&C shall incorporate into such reports information including but not limited to (A) all other matching services linked to SS&C; (B) the time, effort, and cost required to establish each link between SS&C and other matching services; (C) any proposed links between SS&C and other matching services as well as the status of such proposed links; (D) any failure or inability to establish such proposed links or fee schedules for interface charges; (E) any written complaint received from other matching services relating to its established or proposed links with SS&C; and (F) if SS&C failed to adhere to any of the obligations relating to interfaces set forth in conditions B.2.ii(6) through B.2.ii(13) and B.2.ii(16) above, its explanation for such failure. The Commission shall treat information submitted in accordance with this condition as confidential, non-public information, subject to the provisions of applicable law. If any other matching service seeks to link with SS&C more than five years after issuance of an exemptive order issued by the Commission with respect to SS&C's matching service, SS&C shall notify the Commission of the other matching service's request to link with SS&C within ten days of receiving such request. In addition, SS&C shall provide reports to the Commission in accordance with this paragraph commencing six months after the initial request for linkage is made until one year after SS&C and the other matching service begin operating their interface. The Commission reserves the right to request reports from SS&C at any time. SS&C shall provide the Commission with such updated reports within thirty days of the Commission's request.
(18) SS&C shall also publish or make available upon request to any end-user representative the necessary specifications, protocols, and architecture of any interface created by SS&C for any end-user representative.
SS&C is required to file with the Commission amendments to its application for exemption on Form CA-1 if it makes any material change affecting its ETC or matching service—as summarized in this order, in its Form CA-1 dated April 15, 2013, or in any subsequently filed amendments to its Form CA-1—that would make such previously provided information incomplete or inaccurate.
In addition, the Commission may modify by order the terms, scope, or conditions of SS&C's exemption from registration as a clearing agency if it determines that such modification is necessary or appropriate in the public interest, the protection of investors, or otherwise in furtherance of the purposes of the Exchange Act. Furthermore, the Commission may limit, suspend, or revoke this exemption if it finds that SS&C has violated or is unable to comply with any of the provisions set forth in this order if such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Exchange Act.
The Commission believes that the BSTP and SS&C applications demonstrate that BSTP and SS&C will have sufficient operational and processing capabilities to facilitate prompt and accurate matching services and to support the establishment of linked and coordinated facilities for the clearance and settlement of securities transactions. The Commission also notes that BSTP and SS&C's exemptions will be subject to conditions that are designed to enable the Commission to monitor BSTP and SS&C's risk management procedures, operational capacity and safeguards, corporate structure, and ability to operate in a manner to further the fundamental goals of Section 17A of the Exchange Act. Therefore, for the reasons discussed
IT IS HEREBY ORDERED, pursuant to Section 17A(b)(1) of the Exchange Act, that the applications for exemption from registration as a clearing agency under Section 17A(b)(1) filed by Bloomberg STP LLC (File No. 600-33) and SS&C Technologies, Inc. (File No. 600-34) be, and hereby are, approved within the scope described in this order and subject to the terms and conditions contained in this order.
By the Commission.
| Category | Regulatory Information | |
| Collection | Federal Register | |
| sudoc Class | AE 2.7: GS 4.107: AE 2.106: | |
| Publisher | Office of the Federal Register, National Archives and Records Administration |