Page Range | 61583-61972 | |
FR Document |
Page and Subject | |
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81 FR 61663 - Sunshine Act Meeting Notice | |
81 FR 61725 - Sunshine Act Meeting | |
81 FR 61721 - In the Matter of Preston Royalty Corp.; Order of Suspension of Trading | |
81 FR 61681 - Combined Notice of Filings | |
81 FR 61671 - Sunshine Act Meetings | |
81 FR 61680 - Combined Notice of Filings #1 | |
81 FR 61666 - Certain Carbon and Alloy Steel Cut-to-Length Plate From Austria, Belgium, Brazil, the Republic of Korea, Taiwan, and Turkey; Antidumping and Countervailing Duty Investigations: Preliminary Determinations of Critical Circumstances | |
81 FR 61663 - Certain Crystalline Silicon Photovoltaic Products From the People's Republic of China: Partial Rescission of Antidumping Duty Administrative Review | |
81 FR 61664 - Certain Hot-Rolled Carbon Steel Flat Products From India: Notice of Preliminary Results of Antidumping Duty Administrative Review; 2014-2015 | |
81 FR 61703 - Notice of Office of Urban Indian Health Programs Strategic Plan | |
81 FR 61708 - 30-Day Notice of Proposed Information Collection: Application and Recertification Packages for Approval of Nonprofit Organizations in FHA Activities | |
81 FR 61712 - 30-Day Notice of Proposed Information Collection: ConnectHome Use and Benefits Telephone Survey | |
81 FR 61706 - Commercial Fishing Safety Advisory Committee | |
81 FR 61636 - Schedules of Controlled Substances: Temporary Placement of U-47700 Into Schedule I | |
81 FR 61616 - Safety Zone; North Atlantic Ocean, Virginia Beach, VA | |
81 FR 61628 - Privacy Act Regulations | |
81 FR 61683 - Notice of Termination; 10002 Miami Valley Bank, Lakeview, Ohio | |
81 FR 61683 - Notice of Termination, 10046 TeamBank, N.A., Paola, Kansas | |
81 FR 61646 - Defense Federal Acquisition Regulation Supplement: Rights in Technical Data and Validation of Proprietary Data Restrictions (DFARS Case 2012-D022) | |
81 FR 61682 - Good Neighbor Environmental Board; Notification of Public Advisory Committee Teleconference | |
81 FR 61669 - Meeting of the Advisory Committee on Commercial Remote Sensing | |
81 FR 61617 - Chlorantraniliprole; Pesticide Tolerances | |
81 FR 61730 - Notice of Rail Energy Transportation Advisory Committee Meeting | |
81 FR 61619 - Ocean Dumping: Modification of an Ocean Dredged Material Disposal Site Offshore of Charleston, South Carolina | |
81 FR 61615 - Drawbridge Operation Regulation; Lake Washington Ship Canal, Seattle, WA | |
81 FR 61715 - Notice of September 19, 2016, Meeting of the Boston Harbor Islands National Recreation Area Advisory Council | |
81 FR 61675 - Stanford University Power LLC; Supplemental Notice That Initial Market-Based Rate Filing Includes Request For Blanket Section 204 Authorization | |
81 FR 61674 - Rutherford Farm, LLC; Supplemental Notice That Initial Market-Based Rate Filing Includes Request for Blanket Section 204 Authorization | |
81 FR 61675 - Combined Notice of Filings #1 | |
81 FR 61612 - Petition To Initiate Rulemaking; Ensuring That Companies With a History of Financial Insolvency, and Their Subsidiary Companies, Are Not Allowed To Self-Bond Coal Mining Operations | |
81 FR 61616 - Eighth Coast Guard District Annual Safety Zones; Pittsburgh Pirates Fireworks; Allegheny River Mile 0.2 to 0.8 | |
81 FR 61719 - Southern Nuclear Operating Company, Inc., Vogtle Electric Generating Plant, Units 3 and 4; Diverse Actuation System Cabinet Changes | |
81 FR 61719 - President's Committee on the Arts and the Humanities: Meeting #72 | |
81 FR 61721 - Advisory Committee on Reactor Safeguards; Meeting of the ACRS Subcommittee on | |
81 FR 61719 - Advisory Committee on Reactor Safeguards; Meeting of the ACRS Subcommittee on APR 1400; Notice of Meeting | |
81 FR 61671 - Performance Review Board (PRB) | |
81 FR 61670 - Gulf of Mexico Fishery Management Council; Public Meeting | |
81 FR 61670 - Gulf of Mexico Fishery Management Council; Public Meetings | |
81 FR 61595 - Russian Sanctions: Addition of Certain Entities to the Entity List | |
81 FR 61731 - Announcement of Fiscal Year 2016 Low or No Emission Grant Program Project Selections | |
81 FR 61726 - Regents Park Funds, LLC, et al.; Notice of Application | |
81 FR 61674 - Notice of Intent To Prepare a Supplemental Environmental Impact Statement for Disposition of Depleted Uranium Oxide Conversion Product Generated From DOE's Inventory of Depleted Uranium Hexafluoride; Correction | |
81 FR 61733 - Reports, Forms and Recordkeeping Requirements, Agency Information Collection Activity Under OMB Review | |
81 FR 61662 - Fruit and Vegetable Industry Advisory Committee | |
81 FR 61662 - Uinta-Wasatch-Cache Resource Advisory Committee | |
81 FR 61625 - Mariana Archipelago Fisheries; Remove the CNMI Medium and Large Vessel Bottomfish Prohibited Areas | |
81 FR 61677 - Freeport LNG Development, L.P.; Supplemental Notice of Intent To Prepare an Environmental Assessment for the Planned Freeport LNG Train 4 Project and Request for Comments on Environmental Issues | |
81 FR 61674 - Columbia Basin Hydropower; Notice of Intent To File License Application, Filing of Pre-Application Document, Approving Use of the Traditional Licensing Process | |
81 FR 61679 - Delta Air Lines, Inc., Atlas Air, Inc., Polar Air Cargo Worldwide, Inc. v. Enterprise TE Products Pipeline Company LLC; Notice of Complaint | |
81 FR 61681 - Privacy Act of 1974: Notice of Altered Systems of Records | |
81 FR 61676 - Virginia Electric and Power Company v. PJM Interconnection, L.L.C. PJM Settlement, Inc.; Notice of Complaint | |
81 FR 61714 - Notice of Public Meeting, Coeur d'Alene District Resource Advisory Council, Idaho | |
81 FR 61731 - Notice of Availability of the Southern California Metroplex Final Environmental Assessment and Finding of No Significant Impact/Record of Decision | |
81 FR 61730 - Release of Waybill Data | |
81 FR 61713 - Receipt of an Incidental Take Permit Application for Participation in the Amended Oil and Gas Industry Conservation Plan for the American Burying Beetle in Oklahoma | |
81 FR 61714 - Notice of Public Meeting of the Central California Resource Advisory Council | |
81 FR 61669 - Submission for OMB Review; Comment Request | |
81 FR 61672 - Agency Information Collection Activities; Comment Request; William D. Ford Federal Direct Loan Program Repayment Plan Selection Form | |
81 FR 61684 - Board of Scientific Counselors, Office of Infectious Diseases (BSC, OID) | |
81 FR 61684 - Board of Scientific Counselors, National Institute for Occupational Safety and Health (BSC, NIOSH) | |
81 FR 61715 - Crawler, Locomotive, and Truck Cranes Standard; Extension of the Office of Management and Budget's (OMB) Approval of Information Collection (Paperwork) Requirements | |
81 FR 61706 - Agency Information Collection Activities: Proposed Collection; Comment Request | |
81 FR 61737 - Proposed Collection; Comment Request for Form 8038-T | |
81 FR 61739 - Proposed Collection; Comment Request for Form 8610 and Schedule A (Form 8610) | |
81 FR 61734 - Agency Request for Emergency Approval of an Information Collection | |
81 FR 61671 - Agency Information Collection Activities: Submission for OMB Review; Comment Request | |
81 FR 61739 - Proposed Information Collection; Comment Request | |
81 FR 61736 - Proposed Collection; Comment Request for Regulation Project | |
81 FR 61738 - Proposed Collection; Comment Request for Notice 2006-97 | |
81 FR 61738 - Proposed Collection; Comment Request for Regulation Project | |
81 FR 61737 - Proposed Collection; Comment Request for Revenue Procedure | |
81 FR 61725 - Self-Regulatory Organizations; NYSE MKT LLC; Notice of Designation of a Longer Period for Commission Action on a Proposed Rule Change To Amend Certain Rules Relating to Flexible Exchange Options | |
81 FR 61724 - Self-Regulatory Organizations; NYSE Arca, Inc.; Notice of Withdrawal of a Proposed Rule Change, as Modified by Amendment No. 1, To Amend Rule 6.67(c) by Revising the Clearing Member Requirements for Entering an Order into the Electronic Order Capture System | |
81 FR 61730 - Self-Regulatory Organizations; NYSE MKT LLC; Notice of Withdrawal of a Proposed Rule Change, as Modified by Amendment No. 1, To Amend Rule 955NY(c) by Revising the Clearing Member Requirements for Entering an Order Into the Electronic Order Capture System | |
81 FR 61727 - Self-Regulatory Organizations; Chicago Board Options Exchange, Incorporated; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change To Amend the Fees Schedule | |
81 FR 61722 - Self-Regulatory Organizations; NASDAQ PHLX LLC; Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Amend Prior Rule Change, SR-PHLX-2016-38 | |
81 FR 61673 - Agency Information Collection Activities; Submission to the Office of Management and Budget for Review and Approval; Comment Request; Program for the International Assessment of Adult Competencies (PIAAC) 2017 National Supplement | |
81 FR 61708 - Technical Mapping Advisory Council | |
81 FR 61708 - West Virginia; Amendment No. 7 to Notice of a Major Disaster Declaration | |
81 FR 61639 - Anchorage Grounds, Hudson River; Yonkers, NY to Kingston, NY | |
81 FR 61730 - Agency Information Collection Activities: Proposed Collection; Comment Request | |
81 FR 61658 - Endangered and Threatened Wildlife and Plants; Removing the Greater Yellowstone Ecosystem Population of Grizzly Bears From the Federal List of Endangered and Threatened Wildlife | |
81 FR 61683 - Appraisal Subcommittee; Notice of Meeting | |
81 FR 61704 - Prospective Grant of Exclusive Patent License: The Development of an Anti-CD19 Chimeric Antigen Receptor (CAR) for the Treatment of Human Cancers | |
81 FR 61705 - National Heart, Lung, and Blood Institute; Notice of Closed Meeting | |
81 FR 61705 - Eunice Kennedy Shriver National Institute of Child Health & Human Development; Notice of Closed Meetings | |
81 FR 61717 - Records Management; General Records Schedule (GRS); GRS Transmittal 26 | |
81 FR 61703 - Agency Information Collection Activities; Proposed Collection; Public Comment Request | |
81 FR 61639 - Compliance With Title X Requirements by Project Recipients in Selecting Subrecipients | |
81 FR 61583 - MU-2B Series Airplane Training Requirements Update | |
81 FR 61683 - Notice of Termination; 10346 San Luis Trust Bank, FSB; San Luis Obispo, California | |
81 FR 61690 - Authorization of Emergency Use of an In Vitro Diagnostic Device for Detection of Zika Virus; Availability | |
81 FR 61685 - Agency Information Collection Activities; Submission for Office of Management and Budget Review; Comment Request; Requests for Clinical Laboratory Improvement Amendments Categorization | |
81 FR 61685 - Agency Information Collection Activities; Proposed Collection; Comment Request; Human Cells, Tissues, and Cellular and Tissue-Based Products: Establishment Registration and Listing; Eligibility Determination for Donors; and Current Good Tissue Practice | |
81 FR 61700 - Request for Comment on the Status of Vinpocetine | |
81 FR 61647 - Rail Transportation of Grain, Rate Regulation Review; Expanding Access to Rate Relief | |
81 FR 61615 - Professional U.S. Scouting Organization Operations at U.S. Military Installations Overseas; Technical Amendment | |
81 FR 61723 - Voya ETF Trust, et al.; Notice of Application | |
81 FR 61632 - Standards for Safeguarding Customer Information | |
81 FR 61709 - Single Family Mortgage Insurance: Revision of Section 203(k) Consultant Fee Schedule-Solicitation of Comment | |
81 FR 61715 - Final Environmental Impact Statement Non-Federal Oil and Gas Regulations | |
81 FR 61833 - Oil and Gas and Sulfur Operations on the Outer Continental Shelf-Oil and Gas Production Safety Systems | |
81 FR 61941 - Federal Motor Vehicle Safety Standards; Federal Motor Carrier Safety Regulations; Parts and Accessories Necessary for Safe Operation; Speed Limiting Devices | |
81 FR 61741 - Hazardous Materials: Harmonization With International Standards (RRR) |
Agricultural Marketing Service
Forest Service
Industry and Security Bureau
International Trade Administration
National Oceanic and Atmospheric Administration
Patent and Trademark Office
Defense Acquisition Regulations System
Federal Energy Regulatory Commission
Centers for Disease Control and Prevention
Food and Drug Administration
Indian Health Service
National Institutes of Health
Substance Abuse and Mental Health Services Administration
Coast Guard
Federal Emergency Management Agency
Bureau of Safety and Environmental Enforcement
Fish and Wildlife Service
Land Management Bureau
National Park Service
Surface Mining Reclamation and Enforcement Office
Drug Enforcement Administration
Occupational Safety and Health Administration
National Endowment for the Arts
Federal Aviation Administration
Federal Motor Carrier Safety Administration
Federal Transit Administration
National Highway Traffic Safety Administration
Pipeline and Hazardous Materials Safety Administration
Transportation Statistics Bureau
Internal Revenue Service
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Federal Aviation Administration (FAA), DOT.
Final rule; request for comments.
This action relocates and updates the content of SFAR No. 108 to the newly created subpart N of part 91 in order to improve the safety of operating the Mitsubishi Heavy Industries (MHI) MU-2B series airplane. SFAR No. 108 will be eliminated from the Code of Federal Regulations on November 7, 2017, after which time all MU-2B operators must comply with this subpart. The FAA is relocating the training program from the SFAR No. 108 appendices to advisory material in order to allow the FAA to update policy while ensuring significant training adjustments still go through notice-and-comment rulemaking. The FAA is also correcting and updating several inaccurate maneuver profiles to reflect current FAA training philosophy and adding new FAA procedures not previously part of the MU-2B training under SFAR No. 108. This rule will require all MU-2B training programs to meet the requirements of this subpart and to be approved by the FAA to ensure safety is maintained. As a result of this action, operators, training providers, and safety officials will have more timely access to standardized, accurate training material.
This rule is effective on September 7, 2016, except for the removal of SFAR No. 108 to part 91 which is effective on November 7, 2017. The compliance date for this final rule is November 7, 2016. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of September 7, 2016.
Submit comments on or before November 7, 2016.
Send comments identified by docket number FAA-2006-24981 using any of the following methods:
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For technical questions concerning this action, contact Joseph Hemler, Commercial Operations Branch, Flight Standards Service, AFS-820, Federal Aviation Administration, 55 M Street SE., 8th floor, Washington, DC 20003-3522; telephone (202) 267-1100; email
Although the FAA is inviting comments, we have made the determination to adopt this final rule without prior notice and public comment in order to mitigate the safety risks where current Special Federal Aviation Regulation (SFAR) No. 108 conflicts with the FAA's current policy and guidance. The Regulatory Policies and Procedures of the Department of Transportation (DOT), 44 FR 1134 (February 26, 1979), provide that to the maximum extent possible, operating administrations for the DOT should provide an opportunity for public comment on regulations issued without prior notice.
The FAA's authority to issue rules on aviation safety is found in Title 49 of the United States Code (U.S.C.). 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.
This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart III, Section 44701, “General Requirements.” Under that section, Congress charged the FAA with prescribing regulations that set the minimum standards for practices, methods, and procedures necessary for safety in air commerce. This regulation is within the scope of that authority because it will set the minimum level of safety for operation of the Mitsubishi MU-2B.
SFAR No. 108 contained inaccurate MU-2B flight training profiles, and the National Transportation Safety Board (NTSB) recommended that the FAA remedy these inaccuracies as soon as is practical due to serious safety concerns (NTSB Rec. A-14-96 and -97). The FAA concludes that immediate action is necessary to correct the inaccuracies in SFAR No. 108 and, therefore, finds that notice and public comment under 5 U.S.C. 553(b) are impracticable and contrary to the public interest. Further, the FAA finds that good cause exists under 5 U.S.C. 553(d) for making this rule effective immediately upon publication.
Special Federal Aviation Regulation No. 108 mandated training, experience, and operating requirements to improve the safety of operating the MHI MU-2B series airplane. The SFAR contained inaccurate training maneuver profiles and is misaligned with current FAA flight training policy. This action corrects safety-related inaccuracies in the regulation and streamlines the process for updating MU-2B flight training requirements by removing them from regulations and placing them in advisory material. This change will permit the FAA to be more responsive by issuing guidance should any inaccuracies be discovered or should training requirements or policy need to be revised and updated in the future. As a result of this action, pilots, operators, training providers, and safety officials will have more timely and accurate training material.
In 2008, the FAA published SFAR No. 108 to mandate flight training and experience requirements for operators of the MHI MU-2B twin-turboprop aircraft. The rule became effective in 2009 and did not have an expiration date. The flight training and experience requirements were based on an FAA safety evaluation of the aircraft, which has unique control surfaces and characteristics. There is a fleet of approximately 300 aircraft operating today in accordance with 14 CFR parts 91 and 135. In the 20 years leading up to SFAR No. 108, the MU-2B series aircraft experienced 80 accidents with 40 fatalities. Since the effective date of SFAR No. 108, there have only been two fatal accidents. In addition to experience and annual training requirements for pilots, SFAR No. 108 mandated training curriculum and flight profiles for operators and training providers.
Following the issuance of SFAR No. 108 on February 5, 2008, with a compliance date of February 5, 2009, Mitsubishi Heavy Industries of America (MHIA) and Turbine Aircraft Services (TAS), an industry party, began an evaluation to identify errors in flight profiles published in SFAR No. 108. At that time, minor spelling errors and technical items were identified. Additionally, MHIA and TAS notified the FAA of at least one error in procedure in the One Engine Inoperative Maneuvering Loss of Directional Control (Vmc Demonstration) profile.
Additionally, since the publication of SFAR No. 108, the FAA has approved the use of Continued Descent Final Approach (CDFA) procedures in all training programs, including the training programs for the MU-2B. The MU-2B FAA Flight Standardization Board (FSB)
In 2012, the FAA revised its stall recognition and recovery procedures for all aircraft and all training programs by removing the emphasis to ensure a “minimum loss of altitude” when performing stall training maneuvers and by emphasizing a positive reduction in angle of attack procedure as the proper stall recovery method (Advisory Circular (AC) 120-109). The FAA also introduced the use of “startle factor” training through the use of the autopilot during stall recognition and recovery practice in all aircraft training programs. However, the FAA did not include the “startle factor” training in SFAR No. 108.
Both MHIA and TAS requested by letter in early 2012 that the FAA change the MU-2B flight training profiles in SFAR No. 108 and make them consistent with the new stall recognition and recovery procedures. They also suggested the FAA remove the flight training maneuver profiles from SFAR No. 108, for ease of subsequent modification in the event of regulatory or training procedural changes made by the FAA. The FAA recognized that proper stall recognition and recovery is a safety-of-flight concern and concurred that distributing information on how to recover from a stall was essential to proper MU-2B training and safety of flight.
There were a number of conflicts between SFAR No. 108 and best practices and FAA guidance, which demonstrate a better safety record. The FAA's Kansas City Aircraft Evaluation Group (AEG)
First, SFAR No. 108 mandated power and trim settings for the demonstration of a one-engine-inoperative maneuver with loss of directional control. Those settings did not meet the safety standards of current FAA guidance and best practices. The “One Engine Inoperative Maneuvering—Loss of Directional Control” profile in the SFAR differed from current FAA guidance and best practices described in the FAA Airplane Flying Handbook (FAA-H-8083-3A).
Second, CDFA Procedures published in AC 120-108 and published in the MU-2 FSB Report, Revision 4, were not included in the training profiles in SFAR No. 108. Though published in the MU-2 FSB Report, Revision 4, CDFA procedures were not included in the SFAR No. 108 flight training profiles and therefore operators could not use these procedures while operating an MU-2B.
Third, SFAR No. 108 stall-recovery profiles required operators to perform all stall recoveries with a “minimal loss of altitude.” This was inconsistent with stall recovery guidance because the FAA now emphasizes successful recovery from a stall over minimizing the loss of altitude which can lead to a secondary stall. Recent changes to the FAA's stall training policy in AC 120-109 and PTS created conflicts with several flight profiles.
Finally, as identified by Aircraft Evaluation Group (AEG) of the Flight Standards Service and MHI, SFAR No. 108 mandates several airspeeds in appendix D flight profiles that are incorrect.
On October 23, 2014, NTSB urged the FAA to take action on the safety recommendations derived from the NTSB's investigation of a Mitsubishi MU-2B-25 airplane accident in Owasso, Oklahoma. (NTSB Rec. A-14-96 and -97). These recommendations addressed operational training and checklist usage for Mitsubishi MU-2B series airplanes.
The NTSB's investigation found that since SFAR No. 108 became effective in 2008, the FAA has revised its general
The NTSB also recommended in recommendation A-14-97 that “the FAA separate the flight training profiles from the SFAR such that any updates to the profiles can be made without having to go through the rulemaking process.” The FAA interprets this recommendation from the NTSB to mean that the more prescriptive rule in SFAR No. 108 should be revised to a more flexible rule, such as a performance standard. This change will allow flight training profiles to be updated more rapidly in response to improved training best practices and guidance, thus improving operational safety of the MU-2B aircraft.
In order to provide a more flexible regulatory framework for MU-2B training, the FAA is removing all appendices to SFAR No. 108 which contained many prescriptive requirements. With implementation of this rule, all MU-2B training must take place under an FAA approved MU-2B training program. Approval of all MU-2B training programs will be based on whether that program meets the standards of § 91.1705(h).
The following figure describes the changes made from SFAR No. 108 as a result of this final rule and this references the specific sections in the codifications of these requirements in part 91.
The following discussion describes the training program standard established for MU-2B training and contained in subpart N of part 91. These standards are found in § 91.1705(h), and an example of a training program implementing these standards may be found in Advisory Circular accompanying this rule.
Paragraph 91.1705(h) contains the training program standard which replaces the prescriptive content of the former SFAR No. 108's appendices. Paragraph 91.1705(h) requires all MU-2B training programs to include a ground training curriculum, a flight training curriculum, differences training for operators of modified MU-2B aircraft, icing training, and training program hours for ground and flight training. The standard in § 91.1705(h) will allow for updates to MU-2B training programs and allow training providers to keep training programs up to date with current best practices while ensuring that the programs meet the FAA's safety standards. By placing the specific guidance regarding training program content in an AC, the FAA will ensure that the training program specific guidelines can be updated as agency safety philosophy regarding training evolves. However, the requirements for
As required by § 91.1705(h)(1), an MU-2B training program must include a ground training curriculum sufficient to ensure pilot knowledge of MU-2B aircraft systems and procedures necessary for safe operation and proficient pilot knowledge of MU-2B aircraft. The FAA has replaced the prescriptive list of specific items listed in Appendix B to SFAR No. 108 with this performance standard.
As required by § 91.1705(h)(2), an MU-2B training program must also include a flight training curriculum with flight training maneuver profiles sufficient in number and detail to ensure pilot proficiency in all MU-2B operations for each MU-2B Model in accordance with MU-2B aircraft limitations, procedures, and MU-2B cockpit checklist
The FAA has included in subpart N of part 91 a list of specific maneuvers that an MU-2B training program must include in order to ensure pilots are adequately prepared for the unique safety challenges of operating an MU-2B. SFAR No. 108 was more prescriptive because it required these maneuvers in addition to requiring operators to follow all specific airspeeds and the order of procedures of the flight training maneuver profiles. The revised regulation allows for maneuver profiles to be updated with developing training and operational best practices. In order to obtain FAA approval, an MU-2B training program must contain the following flight training maneuver profiles for the MU-2B Model being trained:
• Normal takeoff with 5- and 20- degrees of flaps;
• Takeoff engine failure with 5- and 20- degrees of flaps;
• Takeoff engine failure on a runway or a rejected takeoff;
• Takeoff engine failure after liftoff when unable to climb. This maneuver may be completed in classroom or a flight training device only;
• Steep turns;
• Slow flight maneuvers;
• One engine inoperative maneuvering with a loss of directional control;
• Approach to stall in clean configuration and with wings level;
• Approach to stall in takeoff configuration with 15- to 30- degrees bank;
• Approach to stall in landing configuration with gear down and 40-degrees of flaps;
• Accelerated stall with no flaps;
• Emergency descent at low speed;
• Emergency descent at high speed;
• Unusual attitude recovery with the nose high;
• Unusual attitude recovery with the nose low;
• Normal landing with 20- and 40- degrees flaps;
• Go around and rejected landing;
• No flaps or 5- degrees flaps landing;
• One engine inoperative landing with 5- and 20- degrees of flaps;
• Crosswind landing;
• Instrument landing system (ILS) and missed approach;
• Two engine missed approach;
• One engine inoperative ILS and missed approach;
• One engine inoperative missed approach;
• Non-precision and missed approach;
• Non-precision CDFA and missed approach;
• One engine inoperative non-precision and missed approach;
• One engine inoperative non-precision CDFA and missed approach;
• Circling approach at weather minimums;
• One engine inoperative circling approach at weather minimums.
As required by § 91.1705(h)(3), an MU-2B training program must also include a final phase check sufficient to document pilot proficiency in the flight maneuvers as specified in the approved training programs phase check. This standard replaces the final phase check requirements in former Appendix C to the SFAR No. 108.
As required by § 91.1705(h)(4), an MU-2B training program must also include differences training sufficient to ensure pilot proficiency in each model of the MU-2B aircraft operated by a pilot who operates multiple MU-2B model variants concurrently. The differences training requirement is unchanged from the prior version of SFAR No. 108. Due to the age of the MU-2B fleet currently in operation, many MU-2B aircraft have been modified from the original factory configuration. Therefore, the FAA will continue to mandate differences training in order to ensure that those operators who operate multiple versions of the MU-2B aircraft are adequately trained to safely operate various MU-2B configurations. MU-2B differences requirements have been removed from Appendix A of SFAR No. 108 and are now specified in § 91.1705(h)(4). Section 91.1705(h)(4) only includes differences for factory type design MU-2 aircraft while other applicable MU-2 differences are required by other FAA approved training programs (
As required by § 91.1705(h)(5), an MU-2B training program must also include icing training sufficient to ensure pilot knowledge and safe operation of the MU-2B aircraft in icing conditions as established by Airworthiness Directive 1997-20-14 or an Alternate Means of Compliance to Airworthiness Directive 2000-09-15, as amended.
As required by § 91.1705(h)(6), an MU-2B ground and flight training program must include the training hours identified by § 91.1707(a) for ground instruction, § 91.1707(b) for flight instruction and § 91.1707(c) for differences training. These training hours are identical to SFAR-108 training hours which were initially determined by the FAA's MU-2B FSB as the number of hours necessary to ensure the safe operation of the MU-2B aircraft.
As required by § 91.1707(e), an MU-2B training program must include examples of endorsements for compliance with § 91.1705(f) appropriate to the content of that specific MU-2B training program's compliance with the standards of SFAR No. 108. Section 91.1705(f) describes the endorsement required under § 91.1705 (a) and (b) must be made by:
(1) A certificated flight instructor under part 61 or part 141 meeting the qualifications of § 91.1713; or
(2) a training center evaluator authorized by the FAA to conduct MU-2B evaluation events at a part 142 Training Center meeting the qualifications of § 91.1713 or,
(3) for persons operating the MU-2B for a part 119 certificate holder within the last 12 calendar months, the part 119 certificate holder's flight instructor if that instructor is authorized by the
As required by § 91.1709(a), to obtain approval for an MU-2B training program, training providers must submit a proposed training program to the Administrator. Only training programs approved by the Administrator may be used to satisfy the standards of subpart N of part 91. Training providers may submit for approval the most current version of the appendix to AC 91-MU2B, which the FAA has determined meets the standards of this subpart.
Parts 135, 141, and 142 training providers must submit their proposed training program to their Principal Operations Inspector (POI) or Training Center Program Manager (TCPM) for approval and inclusion in their approved training curriculum.
Part 91 training providers do not have an established process for seeking approval of a training program; therefore, part 91 training providers must submit for approval a proposed training program to their jurisdictional FAA Flight Standards District Office (FSDO). The term `part 91 training providers' refers to training providers providing training under part 61 authority for a part 91 operation. Part 91 training providers may submit for approval the most current version of the appendix to AC 91-MU2B which the FAA has determined meets the standards of subpart N of part 91. The FAA FSDO will issue a Letter of Authorization (LOA) to the training provider if the proposed training program meets the standards of subpart N of part 91. For MU-2B training providers providing training under part 91, training programs will be approved for 24 months, unless sooner superseded or rescinded. For more details on how to submit an MU-2B training program for approval, please see AC 91-MU2B.
Under § 91.1709(a)(3), the Administrator may require revision of an approved MU-2B training program at any time. A training provider must present its approved training program and FAA approval documentation to any representative of the Administrator, upon request.
The FAA is publishing an approved MU-2B training program as an appendix in the AC 91-MU2B Mitsubishi MU-2B Training Program. This AC may be used by training providers to meet the requirements of subpart N of part 91. Training providers may also use this AC as a reference for developing their own MU-2B training programs to submit for FAA approval pursuant to § 91.1709. The AC includes the SFAR No. 108 flight training maneuver profiles with appropriate revisions consistent with current training policy and guidance.
The following updates have been made to the MU-2B flight training profiles which have been removed from SFAR No. 108 and moved to AC 91-MU2B.
The flight training maneuver profiles A-7, B-7, C-7 in the former Appendix D of SFAR No. 108 were incorrect regarding the procedures for setting power and trim for the demonstration of the one-engine-inoperative maneuver with a loss of directional control. The appendix D profile called for the MU-2B aircraft to be configured and trimmed for single engine flight prior to starting the maneuver. The FAA's Airplane Flying Handbook calls for the aircraft to be trimmed for two-engine flight at a slow airspeed and then for the power to be configured for single engine flight without re-trimming. Setting the configuration of the aircraft in the manner SFAR No. 108 required results in the rudder forces required prior to reaching the Velocity Minimum Control (Vmc) being less than the actual rudder forces required to maintain zero sideslip flight. The consequence of setting the configuration in that manner promotes an adverse training condition causing the pilot to under-control the aircraft in the event of an actual Vmc experience. The FAA has revised these maneuver profiles to reflect the proper settings and relocated them to the AC. Section 91.1705(h)(2) retains the requirement that MU-2B pilots train on this item.
An Advisory Circular (AC) published on January 20, 2011, for all aircraft operators, AC 120-108, would enhance the operational safety of an MU-2B aircraft during a non-precision instrument approach. The only non-precision approaches contained in the former version of SFAR No. 108 were those that use the “dive and drive” method, which consists of descending immediately after the final approach fix to the Minimum Descent Altitude (MDA) and then leveling off until reaching the next step down fix or the missed approach point, as appropriate. This SFAR 108 procedure, when accomplished with one engine inoperative, required that the landing gear remain retracted until the pilot had visual contact with the landing runway environment. This SFAR 108 procedure could have resulted in the pilot forgetting to extend the landing gear prior to landing and was seen by many as an unstabilized approach. It also could have resulted in under shooting the visual approach path to the runway, causing a possible controlled-flight-into-terrain (CFIT) accident.
The SFAR 108 “dive and drive” procedure, with gear extension restrictions, was originally approved for the MU-2 by the FAA in 2006 during the FSB review of the MU-2 single engine capabilities. Demonstrations showed a limited or negative climb capability for the MU-2 with the gear in the down position during single engine operations. Since most single engine non-precision approaches result in the need to maintain altitude for a period of time prior to final descent to the landing runway, the FAA determined that a non-standard landing gear configuration would be necessary to safely accomplish the level off. The “dive and drive” procedure is described in the AC 120-108.
The revised procedure allows the pilot the option to extend the landing gear at the normal, final approach fix location and to fly a calculated glide path to the missed approach point, or derived decision altitude. This revised procedure prevents the need to maintain altitude at the MDA with the gear down which, in turn, improves safety. The FAA recognizes this new procedure and the FSB and Aircraft Evaluations Group (AEG) have now revised and published Revision 4 of the FSB Report for the MU-2. This version of the FSB Report contains provisions for incorporating the new procedures into MU-2B training and operation.
The CDFA procedure was not contained in the SFAR No. 108 flight training profiles. The FAA is adding CDFA procedures to the list of required flight training procedures as an additional procedure in § 91.1705(h)(2). These new profiles, in addition to the existing profiles, have been relocated to AC 91-MU2B.
Advisory Circular 120-109 introduced a new procedure for the proper recognition and recovery from a stall for all aircraft. The AC 120-109 is supplemented by Safety Advisory for Operators (SAFO) 10012 standardizing the procedure for all aircraft and training programs. The latest revision of the FAA's Commercial Practical Test Standards calls for a change to the
AC 120-109 resulted from an FAA and industry study of two well-publicized accidents, Colgan Air Flight 3407 and Air France Flight 447. In both of these accidents, the pilots were not immediately aware that the aircraft were stalled, and the pilots did not attempt to recover correctly, resulting in the loss of the aircraft and all passengers.
The maneuver profiles in SFAR No. 108 (profiles A-8 through A-11. B-8 through B-11, and C-8 through C-11) required operators to perform all stall recoveries with a “minimal loss of altitude.” This standard of performance has been redefined for all FAA and industry training for other aircraft, and new profiles have been published in MU-2B Training Program AC to instruct pilots to perform a stall recovery using a positive reduction of angle of attack method. This procedure change is important to ensure that pilots safely recover from a stall and do not cause a secondary stall of the aircraft.
Also, in the past, during advanced training in high performance aircraft like the MU-2B, pilot training did not include full stall recoveries. Historically, recovery would be initiated at the first indication of the stall, which in the case of the MU-2B is a stick shaker vibrating the yoke in order to warn the pilot of an impending stall. Most MU-2B stall training never reaches a full aerodynamic stall or even pre-stall buffet. In those cases, recovery without having to substantially lower the nose of the aircraft is possible, resulting in a minimum loss of altitude. In a full stall, however, a pilot must positively lower the nose to reattach the flow of air to the wing prior to adding power. Otherwise, the pilot risks a secondary stall as the nose rises from addition of power, and/or a torque roll occurs opposite the propeller rotational direction. The new standardized method of recovery from any level of stall condition is to substantially lower the nose.
Recent changes to the FAA's Practical Test Standards direct examiners to assess a pilot's ability to recover promptly at the “onset” (buffeting) stall condition. These revised profiles and AC 120-109 call out procedures for accomplishing this stall recognition and recovery from an autopilot `ON' flight configuration, thereby simulating a stall catching the pilot by surprise and creating more realistic surprise and startle in training. The revised maneuver profiles for stall recognition and recovery have been relocated to the AC.
As required by § 91.1701, after November 7, 2016, all training conducted in an MU-2B must follow an MU-2B training program that meets the standards of this Subpart of part 91. This 60-day period gives training providers time to adjust their training programs to meet the standards of this subpart and to seek FAA approval for training provider developed training programs.
Also required by § 91.1701, this subpart is immediately applicable when effective to all persons who operate a Mitsubishi MU-2B series airplane, including those who act as pilot-in-command (PIC), act as second-in-command (SIC), or other persons who manipulate the controls while under the supervision of a PIC.
As required by § 91.1719, Initial/transition, requalification, or recurrent training conducted prior to November 7, 2016, compliant with SFAR No. 108, Section 3, effective March 6, 2008, is considered to be compliant with this subpart, if the student met the eligibility requirements for the applicable category of training and the student's instructor met the experience requirements of this subpart. This 60-day period allows current operators to continue training under SFAR No. 108 and allows for a seamless transition to training programs under this subpart.
The FAA is immediately relocating and updating the content of SFAR No. 108 to this subpart in order to be in accordance with current FAA policy regarding the safest and most effective means to conduct training in the area of stall recognition and recovery, continuous descent final approach procedures, and one engine inoperative maneuvering. The FAA understands that MU-2B training is currently being conducted consistently with FAA policy and considers such training to be critical to the safe operation of the aircraft. For that reason, the FAA does not anticipate any disruptions in training or operations of MU-2B aircraft as a result of the immediate effective date for this rule. This rulemaking is necessary to align the regulation with the safest, best means to conduct training in the MU-2B.
Changes to Federal regulations must undergo several economic analyses. First, Executive Order 12866 and Executive Order 13563 direct that each Federal agency shall propose or adopt a regulation only upon a reasoned determination that the benefits of the intended regulation justify its costs. Second, the Regulatory Flexibility Act of 1980 (Pub. L. 96-354) requires agencies to analyze the economic impact of regulatory changes on small entities. Third, the Trade Agreements Act (Pub. L. 96-39) prohibits agencies from setting standards that create unnecessary obstacles to the foreign commerce of the United States. In developing U.S. standards, the Trade Act requires agencies to consider international standards and, where appropriate, that they be the basis of U.S. standards. Fourth, the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4) requires agencies to prepare a written assessment of the costs, benefits, and other effects of proposed or final rules that include a Federal mandate likely to result in the expenditure by State, local, or tribal governments, in the aggregate, or by the private sector, of $100 million or more annually (adjusted for inflation with base year of 1995). This portion of the preamble summarizes the FAA's analysis of the economic impacts of this rule.
Department of Transportation Order DOT 2100.5 prescribes policies and procedures for simplification, analysis, and review of regulations. If the expected cost impact is so minimal that a proposed or final rule does not warrant a full evaluation, this order permits that a statement to that effect and the basis for it are to be included in the preamble if a full regulatory evaluation of the cost and benefits is not prepared. Such a determination has been made for this rule. The reasoning for this determination follows:
The purpose and benefit of this action is to correct safety related inaccuracies in the regulation and streamline the process for updating MU-2B flight training profiles should any inaccuracies be discovered or should training requirements or policy need to be revised and updated in the future. As a result of this action, operators, training providers, and safety officials will have timely, accurate training material. This action is important to minimize future accidents.
Pilots in need of MU-2B training can choose from either a training center or hiring one of the approximately 20 MU-2B qualified instructors. Currently, there are three primary training providers that offer FAA approved MU-2B training.
There were a number of conflicts between former SFAR No. 108 and best practices and FAA guidance, which demonstrate a better safety record. The FAA's Kansas City Aircraft Evaluation Group (AEG) and Mitsubishi Heavy Industries (MHI) have documented that the SFAR conflicted with new and
SFAR No. 108 mandates training, experience, and operating requirements to improve the level of operational safety for the MHI MU-2B series airplane. SFAR No. 108 contained inaccurate training profiles and was misaligned with current FAA flight training policy. Since the enactment of SFAR No. 108, there have been two accidents with five fatalities. The SFAR required training in accordance with inaccurate MU-2B flight training profiles. The National Transportation Safety Board (NTSB) recommended that the FAA correct these inaccuracies as soon as is practical. New stall profiles have been created for instructing the pilot to perform a stall recovery using a positive reduction of angle of attack method. This procedure change is important to ensure that pilots safely recover from a stall and do not cause a secondary stall of the aircraft.
Besides the inaccurate training profiles, SFAR 108 was not aligned with current FAA Continuous Descent Final Approach (CDFA) procedures flight training policy published in AC 120-108 and published in the MU-2 FSB Report, Revision 4. FAA CDFA procedures were not contained in the SFAR No. 108 MU-2B flight training profiles. Including these procedures in subpart N of part 91 will allow operators of the MHI MU-2B series airplane to follow the most current procedures when operating an appropriately equipped MHI MU-2B series airplane. The new CDFA flight training supplements training already contained in the SFAR and provides an alternate procedure that may be used at the discretion of the pilot.
The flight training maneuver profiles A-7, B-7, C-7 in former Appendix D of the SFAR No. 108 were incorrect regarding the procedures for setting power and trim for the demonstration of the one-engine-inoperative maneuver with a loss of directional control. Furthermore, the maneuver profiles in the SFAR No. 108 (profiles A-8 through A-11, B-8 through B-11, and C-8 through C-11) required operators to perform all stall recoveries with a “minimal loss of altitude”. This requirement has been removed from all FAA and industry training documents for other aircraft. This rule relocates and updates the content of SFAR No. 108 to this subpart in order to eliminate safety concerns resulting from mandating incorrect and out-of-date best practices for training in and operating the MU-2B.
With this action, all MU-2B training must take place under an FAA approved MU-2B training program. FAA approval of all MU-2B training programs will be based on whether that program meets the performance standards of § 91.1705(h). The FAA is also publishing an AC for the Mitsubishi MU-2B Training Program. This AC Appendix contains a recommended MU-2B training program which may be used by training providers to meet the requirements this subpart, or as a reference for the training providers to develop their own MU-2B training programs.
By following the AC training guidance, there will be no new training costs associated with this revised training guidance. The requalification and recurrent training hours for ground instruction and flight instruction remain the same. All MU-2B pilots will have to take training compliant with this subpart when their 12-month recurrent training requirement comes due, but not before. Nothing in this subpart mandates new training outside the existing currency cycle.
By following the AC training guidance, the change in existing training, results in no new costs. Thus, the cost of the rule will be minimal.
The FAA has, therefore, determined that this rule is not a “significant regulatory action” as defined in section 3(f) of Executive Order 12866, and is not “significant” as defined in DOT's Regulatory Policies and Procedures.
The Regulatory Flexibility Act of 1980 (Public Law 96-354) (RFA) establishes “as a principle of regulatory issuance that agencies shall endeavor, consistent with the objectives of the rule and of applicable statutes, to fit regulatory and informational requirements to the scale of the businesses, organizations, and governmental jurisdictions subject to regulation.” To achieve this principle, agencies are required to solicit and consider flexible regulatory proposals and to explain the rationale for their actions to assure that such proposals are given serious consideration.” The RFA covers a wide-range of small entities, including small businesses, not-for-profit organizations, and small governmental jurisdictions.
Agencies must perform a review to determine whether a rule will have a significant economic impact on a substantial number of small entities. If the agency determines that it will, the agency must prepare a regulatory flexibility analysis as described in the RFA.
However, if an agency determines that a rule is not expected to have a significant economic impact on a substantial number of small entities, section 605(b) of the RFA provides that the head of the agency may so certify and a regulatory flexibility analysis is not required. The certification must include a statement providing the factual basis for this determination, and the reasoning should be clear.
MU-2 aircraft are owned by a substantial number of small entities. However, the FAA believes that this rule does not have a significant economic impact on a substantial number of small entities for the following reasons. With this rule, the updated procedures and new profiles that are already in place for other FAA approved training programs will become mandatory for MU-2B pilots. By following the AC training guidance, the change in existing training, results in no new costs. Nothing in this rule mandates new training outside the existing cycle.
Therefore, as provided in section 605(b), the head of the FAA certifies that this rulemaking will not result in a significant economic impact on a substantial number of small entities.
The Trade Agreements Act of 1979 (Pub. L. 96-39), as amended by the Uruguay Round Agreements Act (Pub. L. 103-465), prohibits Federal agencies from establishing standards or engaging in related activities that create unnecessary obstacles to the foreign commerce of the United States. Pursuant to these Acts, the establishment of standards is not considered an unnecessary obstacle to the foreign commerce of the United States, so long as the standard has a legitimate domestic objective, such as the protection of safety, and does not operate in a manner that excludes imports that meet this objective. The statute also requires consideration of international standards and, where appropriate, that they be the basis for U.S. standards. The FAA has assessed the potential effect of this final rule and determined that the rule would protect safety and is not considered an unnecessary obstacle to foreign commerce.
Title II of the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4) requires each Federal agency to prepare a written statement assessing the effects of any Federal mandate in a proposed or final agency rule that may result in an expenditure of $100 million or more (in 1995 dollars) in any one year by State, local, and tribal governments, in the aggregate, or by the private sector; such a mandate is deemed to be a “significant regulatory action.” The FAA currently uses an inflation-adjusted value of $155 million in lieu of $100 million. This final rule does not contain such a mandate; therefore, the requirements of Title II of the Act do not apply.
The Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)) requires that the FAA consider the impact of paperwork and other information collection burdens imposed on the public. According to the 1995 amendments to the Paperwork Reduction Act (5 CFR 1320.8(b)(2)(vi)), an agency may not collect or sponsor the collection of information, nor may it impose an information collection requirement unless it displays a currently valid Office of Management and Budget (OMB) control number. The FAA has determined that there is a new requirement for information collection associated with this immediately adopted final rule and is requesting the Office of Management and Budget to grant an immediate emergency clearance on the paperwork package that it is submitting. Therefore, notification will be made to the public when a clearance is received. Following is a summary of the information collection activity.
In keeping with U.S. obligations under the Convention on International Civil Aviation, it is FAA policy to conform to International Civil Aviation Organization (ICAO) Standards and Recommended Practices to the maximum extent practicable. The FAA has determined that there are no ICAO Standards and Recommended Practices that correspond to these proposed regulations.
Executive Order 13609, Promoting International Regulatory Cooperation, promotes international regulatory cooperation to meet shared challenges involving health, safety, labor, security, environmental, and other issues and to reduce, eliminate, or prevent unnecessary differences in regulatory requirements. The FAA has analyzed this action under the policies and agency responsibilities of Executive Order 13609, and has determined that this action would have no effect on international regulatory cooperation.
FAA Order 1050.1F identifies FAA actions that are categorically excluded from preparation of an environmental assessment or environmental impact statement under the National Environmental Policy Act in the absence of extraordinary circumstances. The FAA has determined this rulemaking action qualifies for the categorical exclusion identified in paragraph 5-6.6 and involves no extraordinary circumstances.
The FAA has analyzed this immediately adopted final rule under the principles and criteria of Executive Order 13132, Federalism. The agency determined that this action will not have a substantial direct effect on the States, or the relationship between the Federal Government and the States, or on the distribution of power and responsibilities among the various levels of government, and, therefore, does not have Federalism implications.
The FAA analyzed this immediately adopted final rule under Executive Order 13211, Actions Concerning Regulations that Significantly Affect Energy Supply, Distribution, or Use (May 18, 2001). The agency has determined that it is not a “significant energy action” under the executive order and it is not likely to have a significant adverse effect on the supply, distribution, or use of energy.
An electronic copy of a rulemaking document may be obtained by using the Internet—
1. Search the Federal eRulemaking Portal (
2. Visit the FAA's Regulations and Policies Web page at
3. Access the Government Publishing Office's Web page at:
Copies may also be obtained by sending a request (identified by amendment or docket number of this rulemaking) to the Federal Aviation Administration, Office of Rulemaking, ARM-1, 800 Independence Avenue SW., Washington, DC 20591, or by calling (202) 267-9677.
Comments received may be viewed by going to
The Small Business Regulatory Enforcement Fairness Act (SBREFA) of 1996 requires FAA to comply with small entity requests for information or advice about compliance with statutes and regulations within its jurisdiction. A small entity with questions regarding this document, may contact its local FAA official, or the person listed under the
Aircraft, Aviation safety.
Aircraft, Airmen, Airports, Aviation safety, Freight, Incorporation by reference, Reporting and recordkeeping requirements.
Air taxis, Aircraft, Airmen, Alcohol abuse, Aviation safety, Drug abuse, Drug testing, Reporting and recordkeeping requirements.
In consideration of the foregoing, the Federal Aviation Administration amends chapter I of title 14, Code of Federal Regulations as follows:
49 U.S.C. 106(f), 106(g), 40113, 44701-44703, 44707, 44709-44711, 44729, 44903, 45102-45103, 45301-45302.
49 U.S.C. 106(f), 106(g), 1155, 40101, 40103, 40105, 40113, 40120, 44101, 44111, 44701, 44704, 44709, 44711, 44712, 44715, 44716, 44717, 44722, 46306, 46315, 46316, 46504, 46506-46507, 47122, 47508, 47528-47531, 47534, articles 12 and 29 of the Convention on International Civil Aviation (61 stat. 1180), (126 Stat. 11).
(a) On and after November 7, 2016, all training conducted in an MU-2B must follow an approved MU-2B training program that meets the standards of this subpart.
(b) This subpart applies to all persons who operate a Mitsubishi MU-2B series airplane, including those who act as pilot in command, act as second-in-command, or other persons who manipulate the controls while under the supervision of a pilot in command.
(c) This subpart also applies to those persons who provide pilot training for a Mitsubishi MU-2B series airplane. The requirements in this subpart are in addition to the requirements of parts 61, 91, and 135 of this chapter.
(a) Except as provided in paragraph (b) of this section, no person may manipulate the controls, act as PIC, act as second-in-command, or provide pilot training for a Mitsubishi MU-2B series airplane unless that person meets the requirements of this subpart.
(b) A person who does not meet the requirements of this subpart may manipulate the controls of a Mitsubishi MU-2B series airplane if a pilot in command who meets the requirements of this subpart is occupying a pilot station, no passengers or cargo are carried on board the airplane, and the flight is being conducted for one of the following reasons—
(1) The pilot in command is providing pilot training to the manipulator of the controls;
(2) The pilot in command is conducting a maintenance test flight with a second pilot or certificated mechanic; or
(3) The pilot in command is conducting simulated instrument flight and is using a safety pilot other than the pilot in command who manipulates the controls for the purposes of § 91.109(b).
(c) A person is required to complete
(1) 50 hours of documented flight time manipulating the controls while serving as pilot in command of a Mitsubishi MU-2B series airplane in the preceding 24 months; or
(2) 500 hours of documented flight time manipulating the controls while serving as pilot in command of a Mitsubishi MU-2B series airplane.
(d) A person is eligible to receive
(1) 50 hours of documented flight time manipulating the controls while serving as pilot in command of a Mitsubishi MU-2B series airplane in the preceding 24 months; or
(2) 500 hours of documented flight time manipulating the controls while serving as pilot in command of a Mitsubishi MU-2B series airplane.
(e) A person is required to complete
(f) Successful completion of Initial/transition training or Requalification training is a one-time requirement. A person may elect to retake Initial/transition training or Requalification training in lieu of Recurrent training.
(g) A person is required to complete Differences training in accordance with an FAA approved MU-2B training program if that person operates more than one MU-2B model as specified in § 91.1707(c).
(a) Except as provided in § 91.1703(b), no person may manipulate the controls, act as pilot in command, or act as second-in-command of a Mitsubishi MU-2B series airplane for the purpose of flight unless—
(1) The requirements for ground and flight training on Initial/transition, Requalification, Recurrent, and Differences training have been completed in accordance with an FAA approved MU-2B training program that meets the standards of this subpart; and
(2) That person's logbook has been endorsed in accordance with paragraph (f) of this section.
(b) Except as provided in § 91.1703(b), no person may manipulate the controls, act as pilot in command, or act as second-in-command, of a Mitsubishi MU-2B series airplane for the purpose of flight unless—
(1) That person satisfactorily completes, if applicable, annual Recurrent pilot training on the
(2) That person's logbook has been endorsed in accordance with paragraph (f) of this section.
(c) Satisfactory completion of the competency check required by § 135.293 of this chapter within the preceding 12
(d) Satisfactory completion of a Federal Aviation Administration sponsored pilot proficiency program, as described in § 61.56(e) of this chapter may not be substituted for the Mitsubishi MU-2B series airplane annual recurrent flight training of this section.
(e) If a person complies with the requirements of paragraph (a) or (b) of this section in the calendar month before or the calendar month after the month in which compliance with these paragraphs are required, that person is considered to have accomplished the training requirement in the month the training is due.
(f) The endorsement required under paragraph (a) and (b) of this section must be made by—
(1) A certificated flight instructor or a simulator instructor authorized by a Training Center certificated under part 142 of this chapter and meeting the qualifications of § 91.1713; or
(2) For persons operating the Mitsubishi MU-2B series airplane for a 14 CFR part 119 certificate holder within the last 12 calendar months, the part 119 certificate holder's flight instructor if authorized by the FAA and if that flight instructor meets the requirements of § 91.1713.
(g) All training conducted for a Mitsubishi MU-2B series airplane must be completed in accordance with an MU-2B series airplane checklist that has been accepted by the Federal Aviation Administration's MU-2B Flight Standardization Board or the applicable MU-2B series checklist (incorporated by reference, see § 91.1721).
(h) MU-2B training programs must contain ground training and flight training sufficient to ensure pilot proficiency for the safe operation of MU-2B aircraft, including:
(1) A ground training curriculum sufficient to ensure pilot knowledge of MU-2B aircraft, aircraft systems, and procedures, necessary for safe operation; and
(2) Flight training curriculum including flight training maneuver profiles sufficient in number and detail to ensure pilot proficiency in all MU-2B operations for each MU-2B model in correlation with MU-2B limitations, procedures, aircraft performance, and MU-2B Cockpit Checklist procedures applicable to the MU-2B model being trained. A MU-2B training program must contain, at a minimum, the following flight training maneuver profiles applicable to the MU-2B model being trained:
(i) Normal takeoff with 5- and 20- degrees flaps;
(ii) Takeoff engine failure with 5- and 20- degrees flaps;
(iii) Takeoff engine failure on runway or rejected takeoff;
(iv) Takeoff engine failure after liftoff—unable to climb (may be completed in classroom or flight training device only);
(v) Steep turns;
(vi) Slow flight maneuvers;
(vii) One engine inoperative maneuvering with loss of directional control;
(viii) Approach to stall in clean configuration and with wings level;
(ix) Approach to stall in takeoff configuration with 15- to 30- degrees bank;
(x) Approach to stall in landing configuration with gear down and 40-degrees of flaps;
(xi) Accelerated stall with no flaps;
(xii) Emergency descent at low speed;
(xiii) Emergency descent at high speed;
(xiv) Unusual attitude recovery with the nose high;
(xv) Unusual attitude recovery with the nose low;
(xvi) Normal landing with 20- and 40- degrees flaps;
(xvii) Go around and rejected landing;
(xviii) No flap or 5- degrees flaps landing;
(xix) One engine inoperative landing with 5- and 20- degrees flaps;
(xx) Crosswind landing;
(xxi) Instrument landing system (ILS) and missed approach ;
(xxii) Two engine missed approach;
(xxiii) One engine inoperative ILS and missed approach;
(xxiv) One engine inoperative missed approach;
(xxv) Non-precision and missed approach;
(xxvi) Non-precision continuous descent final approach and missed approach;
(xxvii) One engine inoperative non-precision and missed approach;
(xxviii) One engine inoperative non-precision CDFA and missed approach;
(xxix) Circling approach at weather minimums;
(xxx) One engine inoperative circling approach at weather minimums.
(3) Flight training must include a final phase check sufficient to document pilot proficiency in the flight training maneuver profiles at the completion of training; and
(4) Differences training for applicable MU-2B model variants sufficient to ensure pilot proficiency in each model operated. Current MU-2B differences requirements are specified in § 91.1707(c). A person must complete Differences training if a person operates more than one MU-2B model as specified in § 91.1707(c). Differences training between the factory type design K and M models of the MU-2B airplane, and the factory type design J and L models of the MU-2B airplane, may be accomplished with Level A training. All other factory type design differences training must be accomplished with Level B training unless otherwise specified in § 91.1707(c) . A Level A or B differences training is not a recurring annual requirement. Once a person has completed Initial Level A or B Differences training between the applicable different models, no additional differences training between those models is required.
(5) Icing training sufficient to ensure pilot knowledge and safe operation of the MU-2B aircraft in icing conditions as established by the FAA;
(6) Ground and flight training programs must include training hours identified by § 91.1707(a) for ground instruction, § 91.1707(b) for flight instruction, and § 91.1707(c) for differences training.
(i) No training credit is given for second-in-command training and no credit is given for right seat time under this program. Only the sole manipulator of the controls of the MU-2B airplane, flight training device, or Level C or D simulator can receive training credit under this program;
(ii) An MU-2B airplane must be operated in accordance with an FAA approved MU-2B training program that meets the standards of this subpart and the training hours in § 91.1707.
(7) Endorsements given for compliance with paragraph (f) of this section must be appropriate to the content of that specific MU-2B training program's compliance with standards of this subpart.
(a) Ground instruction hours are listed in the following table:
(b) Flight instruction hours are listed in the following table:
(c) Differences training hours are listed in the following table:
(d) Definitions of levels of training as used in this subpart:
(1) LEVEL A Training—Training that is conducted through self-instruction by the pilot.
(2) LEVEL B Training—Training that is conducted in the classroom environment with the aid of a qualified instructor who meets the requirements of this subpart.
(3) LEVEL C Training—Training that is accomplished in an FAA-approved Level 5 or 6 flight training device. In addition to the basic FTD requirements, the FTD must be representative of the MU-2B cockpit controls and be specifically approved by the FAA for the MU-2B airplane.
(4) Level E Training—Training that must be accomplished in the MU-2B airplane, Level C simulator, or Level D simulator.
To obtain approval for an MU-2B training program, training providers must submit a proposed training program to the Administrator.
(a) Only training programs approved by the Administrator may be used to satisfy the standards of this subpart.
(b) For part 91 training providers, training programs will be approved for 24 months, unless sooner superseded or rescinded.
(c) The Administrator may require revision of an approved MU-2B training program at any time.
(d) A training provider must present its approved training program and FAA approval documentation to any representative of the Administrator, upon request.
No person may act as a pilot in command of a Mitsubishi MU-2B series airplane for the purpose of flight unless that person holds an airplane category and multi-engine land class rating, and has logged a minimum of 100 flight hours of PIC time in multi-engine airplanes.
(a)
(1) Meets the pilot training and documentation requirements of § 91.1705 before giving flight instruction in the Mitsubishi MU-2B series airplane;
(2) Meets the currency requirements of §§ 91.1715(a) and 91.1715(c)
(3) Has a minimum total pilot time of 2,000 pilot-in-command hours and 800 pilot-in-command hours in multiengine airplanes; and
(4) Has:
(i) 300 pilot-in-command hours in the Mitsubishi MU-2B series airplane, 50 hours of which must have been within the preceding 12 months; or
(ii) 100 pilot-in-command hours in the Mitsubishi MU-2B series airplane, 25 hours of which must have been within the preceding 12 months, and 300 hours providing instruction in a FAA-approved Mitsubishi MU-2B simulator or FAA-approved Mitsubishi MU-2B flight training device, 25 hours of which must have been within the preceding 12 months.
(b)
(1) Each flight instructor who provides flight training for the Mitsubishi MU-2B series airplane must meet the pilot training and documentation requirements of § 91.1705 before giving flight instruction for the Mitsubishi MU-2B series airplane;
(2) Each flight instructor who provides flight training for the Mitsubishi MU-2B series airplane must meet the currency requirements of § 91.1715(c) before giving flight instruction for the Mitsubishi MU-2B series airplane;
(3) Each flight instructor who provides flight training for the Mitsubishi MU-2B series airplane must have:
(i) A minimum total pilot time of 2000 pilot-in-command hours and 800 pilot-in-command hours in multiengine airplanes; and
(ii) Within the preceding 12 months, either 50 hours of Mitsubishi MU-2B series airplane pilot-in-command experience or 50 hours providing simulator or flight training device instruction for the Mitsubishi MU-2B.
(c)
(1) For the purpose of checking, designated pilot examiners, training center evaluators, and check airmen must have completed the appropriate training in the Mitsubishi MU-2B series airplane in accordance with § 91.1705;
(2) For checking conducted in the Mitsubishi MU-2B series airplane, each designated pilot examiner and check airman must have 100 hours pilot-in-command flight time in the Mitsubishi MU-2B series airplane and maintain currency in accordance with § 91.1715.
(a) The takeoff and landing currency requirements of § 61.57 of this chapter must be maintained in the Mitsubishi MU-2B series airplane. Takeoff and landings in other multiengine airplanes do not meet the takeoff landing currency requirements for the Mitsubishi MU-2B series airplane. Takeoff and landings in either the short-body or long-body Mitsubishi MU-2B model airplane may be credited toward takeoff and landing currency for both Mitsubishi MU-2B model groups.
(b) Instrument experience obtained in other category and class of aircraft may be used to satisfy the instrument currency requirements of § 61.57 of this chapter for the Mitsubishi MU-2B series airplane.
(c) Satisfactory completion of a flight review to satisfy the requirements of § 61.56 of this chapter is valid for operation of a Mitsubishi MU-2B series airplane only if that flight review is conducted in a Mitsubishi MU-2B series airplane or an MU-2B Simulator approved for landings with an approved course conducted under part 142 of this chapter. The flight review for Mitsubishi MU-2B series airplanes must include the
(d) A person who successfully completes the Initial/transition, Requalification, or Recurrent training requirements under § 91.1705 of this chapter also meet the requirements of § 61.56 of this chapter and need not accomplish a separate flight review provided that at least 1 hour of the flight training was conducted in the Mitsubishi MU-2B series airplane or an MU-2B Simulator approved for landings with an approved course conducted under part 142 of this chapter.
(a) Except as provided in paragraph (b) of this section, no person may operate a Mitsubishi MU-2B airplane in single pilot operations unless that airplane has a functional autopilot.
(b) A person may operate a Mitsubishi MU-2B airplane in single pilot operations without a functional autopilot when—
(1) Operating under day visual flight rule requirements; or
(2) Authorized under a FAA approved minimum equipment list for that airplane, operating under instrument flight rule requirements in daytime visual meteorological conditions.
(c) No person may operate a Mitsubishi MU-2B series airplane unless a copy of the appropriate Mitsubishi Heavy Industries MU-2B Airplane Flight Manual is carried on board the airplane and is accessible during each flight at the pilot station.
(d) No person may operate a Mitsubishi MU-2B series airplane unless an MU-2B series airplane checklist, appropriate for the model being operated and accepted by the Federal Aviation Administration MU-2B Flight Standardization Board, is accessible for each flight at the pilot station and is used by the flight crewmembers when operating the airplane.
(e) No person may operate a Mitsubishi MU-2B series airplane contrary to the standards of this subpart.
(f) If there are any differences between the training and operating requirements of this subpart and the MU-2B Airplane Flight Manual's procedures sections (Normal, Abnormal, and Emergency) and the MU-2B airplane series checklist incorporated by reference in § 91.1721, the person operating the airplane must operate the airplane in accordance with the training specified in this subpart.
Initial/transition, requalification, recurrent or Level B differences training conducted prior to November 7, 2016, compliant with SFAR No. 108, Section 3 of this part, is considered to be compliant with this subpart, if the student met the eligibility requirements for the applicable category of training and the student's instructor met the experience requirements of this subpart.
(a) The Mitsubishi Heavy Industries MU-2B Cockpit Checklists are incorporated by reference into this part. The Director of the Federal Register approved this incorporation by reference in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. All approved material is available for inspection at U.S. Department of Transportation, Docket Management Facility, Room W 12-140, West Building Ground Floor, 1200 New Jersey Ave. SE., Washington, DC 20590-0001, or at the National Archives and Records Administration, call 202-741-6030, or go to:
(b) Turbine Aircraft Services, Inc., 4550 Jimmy Doolittle Drive, Addison, Texas 75001, USA.
(1) Mitsubishi Heavy Industries MU-2B Checklists:
(i) Cockpit Checklist, Model MU-2B-60, Type Certificate A10SW, MHI Document No. YET06220C, accepted by FSB on February 12, 2007.
(ii) Cockpit Checklist, Model MU-2B-40, Type Certificate A10SW, MHI Document No. YET06256A, accepted by FSB on February 12, 2007.
(iii) Cockpit Checklist, Model MU-2B-36A, Type Certificate A10SW, MHI Document No. YET06257B, accepted by FSB on February 12, 2007.
(iv) Cockpit Checklist, Model MU-2B-36, Type Certificate A2PC, MHI Document No. YET06252B, accepted by FSB on February 12, 2007.
(v) Cockpit Checklist, Model MU-2B-35, Type Certificate A2PC, MHI Document No. YET06251B, accepted by FSB on February 12, 2007.
(vi) Cockpit Checklist, Model MU-2B-30, Type Certificate A2PC, MHI Document No. YET06250A, accepted by FSB on March 2, 2007.
(vii) Cockpit Checklist, Model MU-2B-26A, Type Certificate A10SW, MHI Document No. YET06255A, accepted by FSB on February 12, 2007.
(viii) Cockpit Checklist, Model MU-2B-26, Type Certificate A2PC, MHI Document No. YET06249A, accepted by FSB on March 2, 2007.
(ix) Cockpit Checklist, Model MU-2B-26, Type Certificate A10SW, MHI Document No. YET06254A, accepted by FSB on March 2, 2007.
(x) Cockpit Checklist, Model MU-2B-25, Type Certificate A10SW, MHI Document No. YET06253A, accepted by FSB on March 2, 2007.
(xi) Cockpit Checklist, Model MU-2B-25, Type Certificate A2PC, MHI Document No. YET06248A, accepted by FSB on March 2, 2007.
(xii) Cockpit Checklist, Model MU-2B-20, Type Certificate A2PC, MHI Document No. YET06247A, accepted by FSB on February 12, 2007.
(xv) Cockpit Checklist, Model MU-2B-15, Type Certificate A2PC, MHI Document No. YET06246A, accepted by FSB on March 2, 2007.
(xvi) Cockpit Checklist, Model MU-2B-10, Type Certificate A2PC, MHI Document No. YET06245A, accepted by FSB on March 2, 2007.
(xvii) Cockpit Checklist, Model MU-2B, Type Certificate A2PC, MHI Document No. YET06244A, accepted by FSB on March 2, 2007.
(2) [Reserved]
49 U.S.C. 106(f), 106(g), 41706, 40113, 44701-44702, 44705, 44709, 44711-44713, 44715-44717, 44722, 44730, 45101-45105; Pub. L. 112-95, 126 Stat. 58 (49 U.S.C. 44730).
Bureau of Industry and Security, Commerce.
Final rule.
The Bureau of Industry and Security (BIS) amends the Export Administration Regulations (EAR) by adding eighty-one entities under eighty-six entries to the Entity List. The eighty-one entities who are added to the Entity List have been determined by the U.S. Government to be acting contrary to the national security or foreign policy interests of the United States. BIS is taking this action to ensure the efficacy of existing sanctions on the Russian Federation (Russia) for violating international law and fueling the conflict in eastern Ukraine. These entities will be listed on the Entity List under the destinations of the Crimea region of Ukraine, Hong Kong, India, and Russia.
This rule is effective September 7, 2016.
Chair, End-User Review Committee, Office of the Assistant Secretary, Export Administration, Bureau of Industry and Security, Department of Commerce, Phone: (202) 482-5991, Email:
The Entity List (Supplement No. 4 to Part 744 of the EAR) identifies entities and other persons reasonably believed to be involved in, or that pose a significant risk of being or becoming involved in, activities that are contrary to the national security or foreign policy of the United States. The EAR imposes additional licensing requirements on, and limits the availability of most license exceptions for, exports, reexports, and transfers (in-country) to those persons or entities listed on the Entity List. The license review policy for each listed entity is identified in the License Review Policy column on the Entity List and the impact on the availability of license exceptions is described in the
The End-user Review Committee (ERC) is composed of representatives of the Departments of Commerce (Chair), State, Defense, Energy, and where appropriate, the Treasury. The ERC makes decisions to add an entry to the Entity List by majority vote and to remove or modify an entry by unanimous vote. The Departments represented on the ERC have approved these changes to the Entity List.
This rule implements the decision of the ERC to add eighty-one entities under eighty-six entries to the Entity List. These eighty-one entities are being added on the basis of § 744.11 (License requirements that apply to entities acting contrary to the national security or foreign policy interests of the United States) of the EAR. The eighty-six entries being added to the Entity List consist of seven entries in the Crimea region of Ukraine, two entries in Hong Kong, two entries in India, and seventy-five entries in Russia. There are eighty-six entries for the eighty-one entities because five entities are listed in multiple locations, resulting in five additional entries.
Under § 744.11(b) (Criteria for revising the Entity List) of the EAR, persons for whom there is reasonable cause to believe, based on specific and articulable facts, have been involved, are involved, or pose a significant risk of being or becoming involved in, activities that are contrary to the national security or foreign policy interests of the United States and those acting on behalf of such persons may be added to the Entity List. The entities being added to the Entity List have been determined to be involved in activities that are contrary to the national security or foreign policy interests of the United States. Specifically, in this rule, BIS adds entities to the Entity List for violating international law and fueling the conflict in eastern Ukraine. These additions ensure the efficacy of existing sanctions on Russia. The particular additions to the Entity List and related authorities are as follows.
One entity is added based on activities that are described in Executive Order 13660 (79 FR 13493),
Executive Order 13660 blocks all property and interests in property that are in the United States, that come within the United States, or that are or come within the possession or control of any United States person (including any foreign branch) of any person determined by the Secretary of the Treasury, in consultation with the Secretary of State, to be responsible for or complicit in, or to have engaged in, directly or indirectly, misappropriation of state assets of Ukraine or of an economically significant entity in Ukraine, among other activities. Under Section 8 of the Order, all agencies of the United States Government are directed to take all appropriate measures within their authority to carry out the provisions of the Order.
The Department of the Treasury's Office of Foreign Assets Control, pursuant to Executive Order 13660, has designated the following entity: Salvation Committee of Ukraine, as being within the scope of the Order. In conjunction with that designation, BIS adds Salvation Committee of Ukraine to the Entity List under this rule and imposes a license requirement for exports, reexports, or transfers (in-country) of all items subject to the EAR to this blocked entity. This license requirement implements an appropriate
Eleven entities are added based on activities that are described in Executive Order 13661 (79 FR 15533),
Executive Order 13661 includes a directive that all property and interests in property that are in the United States, that hereafter come within the United States, or that are or thereafter come within the possession or control of any United States person (including any foreign branch) of the following persons are blocked and may not be transferred, paid, exported, withdrawn, or otherwise dealt in: Persons determined by the Secretary of the Treasury, in consultation with the Secretary of State to have either materially assisted, sponsored or provided financial, material or technological support for, or goods and services to or in support of a senior official of the government of the Russian Federation or to operate in the defense or related materiel sector in Russia. Under Section 8 of the Order, all agencies of the United States Government are directed to take all appropriate measures within their authority to carry out the provisions of the Order.
BIS, pursuant to Executive Order 13661, and in consultation with the Departments of State, Defense, Energy, and the Treasury, has designated the following eleven entities: Angstrem-M; Giovan Ltd.; Joint Stock Company Angstrem; Joint Stock Company Angstrem-T; Joint Stock Company Foreign Economic Association (FEA) Radioexport; Joint Stock Company Perm Scientific Industrial Instrument-Making Company (PNPPK); Joint Stock Company Mikron; Joint Stock Company Research and Production Company Micran; NPC Granat; Technopole Company; and Technopole Ltd. The eleven entities added to the Entity List under Executive Order 13661 meet the criteria of Section 1, subparagraph B of the Order because they operate in Russia's arms or related materiel sector. BIS adds all eleven of those entities to the Entity List under this rule, and imposes a license requirement for exports, reexports, or transfers (in-country) of all items subject to the EAR to these entities. This license requirement implements an appropriate measure within the authority of the EAR to carry out the provisions of Executive Order 13661.
Fifty-one entities are added to the Entity List based on activities that are described in Executive Order 13662 (79 FR 16169),
The Department of the Treasury's Office of Foreign Assets Control, pursuant to Executive Order 13662, on behalf of the Secretary of the Treasury, and in consultation with the Secretary of State, has designated the following fifty-one entities as operating in the energy sector of Russia and owned or controlled by, or have acted or purported to act for or on behalf of, directly or indirectly, Gazprom, OAO, a person whose property and interests are blocked pursuant to the Order: Achim Development, OOO; Daltransgaz, OAO; Druzhba, AO; Gaz-Oil, OOO; Gazmash, AO; Gazprom Dobycha Irkutsk, OOO; Gazprom Dobycha Krasnodar, OOO; Gazprom Dobycha Kuznetsk, OOO; Gazprom Dobycha Nadym, OOO; Gazprom Dobycha Noyabrsk, OOO; Gazprom Dobycha Urengoi, OOO; Gazprom Dobycha Yamburg, OOO; Gazprom Energo, OOO; Gazprom Flot, OOO; Gazprom Gaznadzor, OOO; Gazprom Gazobezopasnost, OOO; Gazprom Geologorazvedka, OOO; Gazprom Inform, OOO; Gazprom Invest, OOO; Gazprom Kapital, OOO; Gazprom Komplektatsiya, OOO; Gazprom Mezhregiongaz, OOO; Gazprom Pererabotka, OOO; Gazprom Personal, OOO; Gazprom Promgaz, AO; Gazprom Russkaya, OOO; Gazprom Sotsinvest, OOO; Gazprom Svyaz, OOO; Gazprom Telekom, OOO; Gazprom Transgaz Kazan, OOO; Gazprom Transgaz Krasnodar, OOO; Gazprom Transgaz Makhachkala, OOO; Gazprom Transgaz Nizhni Novgorod, OOO; Gazprom Transgaz Samara, OOO; Gazprom Transgaz Sankt-Peterburg, OOO; Gazprom Transgaz Saratov, OOO; Gazprom Transgaz Stavropol, OOO; Gazprom Transgaz Surgut, OOO; Gazprom Transgaz Tomsk, OOO; Gazprom Transgaz Ufa, OOO; Gazprom Transgaz Ukhta, OOO; Gazprom Transgaz Volgograd, OOO; Gazprom Transgaz Yugorsk, OOO; Gazprom Tsentrremont, OOO; Gazprom Vniigaz, OOO; Kamchatgazprom OAO; Krasnoyarskgazprom, PAO; Lazurnaya, OOO; Niigazekonomika, OOO; Vostokgazprom, OAO; and Yamalgazinvest, ZAO. In conjunction with that designation, BIS adds all fifty-one of the entities to the Entity List under this rule and imposes a license requirement for exports, reexports, or transfers (in-country) of all items subject to the EAR to these blocked persons, when the exporter, reexporter or transferor knows that the item will be used directly or indirectly in exploration for, or production of, oil or gas in Russian deepwater (greater than 500 feet) or Arctic offshore locations or shale formations in Russia, or is unable to determine whether the item will be used in such projects. All of these persons are subsidiaries of Gazprom, which was added to the Entity List on September 17, 2014 (79 FR 55608). This license requirement implements an appropriate measure within the authority of BIS to carry out the provisions of Executive Order 13662.
Eighteen entities are added based on activities that are described in Executive Order 13685 (79 FR 77357),
The Department of the Treasury's Office of Foreign Assets Control, pursuant to Executive Order 13685 on behalf of the Secretary of the Treasury and in consultation with the Secretary of State, has designated the following eighteen entities as operating in the Crimea region of Ukraine: AO `Institute Giprostroymost—Saint-Petersburg'; CJSC Sovmortrans; FAU `Glavgosekspertiza Rossii'; FKU Uprdor `Taman'; Federal SUE Shipyard `Morye'; LLC Koksokhimtrans; OAO Ship Repair Center `Zvezdochka'; OJSC Sovfracht; OAO `Uranis-Radiosistemy'; OOO `DSK'; OOO Shipyard `Zaliv'; OOO `STG-EKO'; PJSC Mostotrest; SGM Most OOO; SMT-K; Sovfracht Managing Company, LLC; Sovfracht-Sovmortrans Group; and Sue RC `Feodosia Optical Plant'. In conjunction with that designation, BIS adds all eighteen of these entities to the Entity List under this rule and imposes a license requirement for exports, reexports, or transfers (in-country) of all items subject to the EAR to these blocked persons. This license requirement implements an appropriate measure within the authority of the EAR to carry out the provisions of Executive Order 13685.
For the thirty entities under thirty-five entries added to the Entity List based on activities that are described in Executive Orders 13660, 13661, or 13685, BIS imposes license requirement for all items subject to the EAR and a license review policy of presumption of denial. The license requirement applies to any transaction in which items are to be exported, reexported, or transferred (in-country) to any of the entities or in which such entities act as purchaser, intermediate consignee, ultimate consignee, or end-user.
For the fifty-one Russian subsidiaries of Gazprom, OAO, that are added to the Entity List based on activities described in Executive Order 13662, the BIS imposes a license requirement for the export, reexport or transfers (in-country) of all items subject to the EAR to those companies when the exporter, reexporter or transferor knows that the item will be used directly or indirectly in exploration for, or production of, oil or gas in Russian deepwater (greater than 500 feet) or Arctic offshore locations or shale formations in Russia, or is unable to determine whether the item will be used in such projects. License applications for the fifty-one Russian subsidiaries will be reviewed with a presumption of denial when the items are for use directly or indirectly for exploration or production from deepwater (greater than 500 feet), Arctic offshore, or shale projects in Russia that have the potential to produce oil. In addition, no license exceptions are available for exports, reexports, or transfers (in-country) to any of the entities being added to the Entity List in this rule.
The acronyms “a.k.a.” (also known as) and “f.k.a.” (formerly known as) are used in entries on the Entity List to help exporters, reexporters and transferors to better identify listed persons on the Entity List.
This final rule adds the following eighty-one entities under eighty-six entries to the Entity List:
(1)
13 Demidova Street, Sevastopol, Crimea, Ukraine;
(2)
1 Desantnikov Street, Feodosia, Crimea 98176, Ukraine;
(3)
33 G, Vakulenchuk Street, Sevastopol, Crimea 99053, Ukraine;
(4)
13 Geroyev Sevastopolya Street, Sevastopol, Crimea 99001, Ukraine (See alternate address in Russia);
(5)
4 Tankistov Street, Kerch, Crimea 98310, Ukraine;
(6)
ul. Zoi Zhiltsovoy, d. 15, office 51, Simferopol, Crimea, Ukraine;
(7)
Feodosia State Optical Plant, 11 Moskovskaya Street, Feodosia, Crimea 98100, Ukraine.
(1)
(2)
(1)
(2)
(1)
d.7 ul.Promyshlennaya, Novy Urengoi, Yamalo-Nenetski a.o. 629306, Russia;
(2)
(3)
7 Yablochkova Street, St. Petersburg 197198, Russia;
(4)
Rakhmanovskiy lane, 4, bld.1, Morskoy House, Moscow 127994, Russia;
(5)
d. 1 ul.Solnechnaya S. Ilinka, Khabarovski Raion Khabarovski krai 680509, Russia;
(6)
Rogozinino, Moscow 143397, Russia;
(7)
Furkasovskiy Lane, building 6, Moscow 101000, Russia (See alternate address under Crimea region of Ukraine);
(8)
3 Revolution Avenue, Anapa, Krasnodar 353440, Russia;
(9)
d.10 B ul.Nametkina, Moscow 117420, Russia;
(10)
d. 54 korp. 1 litera A pomeshch prospekt Primorski, St. Petersburg 197374, Russia;
(11)
d.14 ul.Nizhnyaya Naberezhnaya, Irkutsk, Irkutskaya obl 664011, Russia;
(12)
d.53 ul.Shosse Neftyanikov, Krasnodar, Krasnodarski krai 350051, Russia;
(13)
d.4 prospekt Oktyabrski, Kemerovo, Kemerovskaya obl 650066, Russia;
(14)
d.1 ul.Zvereva, Nadym, Yamalo-Nenetski a.o. 629730, Russia;
(15)
d.20 ul. Respubliki, Noyabrsk, Yamalo-Nenetski a.o. 629802, Russia;
(16)
d.8 ul.Zheleznodorozhnaya, Novy Urengoi, Yamalo-Nenetski a.o. 629307, Russia;
(17)
d.9 ul. Geologorazvedchikov, Novy Urengoi, Yamalo-Nenetski a.o 629306, Russia;
(18)
8 Korp. 1 ul.Stroitelei, Moscow 117939, Russia;
(19)
d. 12 A ul.Nametkina, Moscow 117420, Russia;
(20)
41 str. 1 prospekt Vernadskogo, Moscow 119415, Russia;
(21)
d. 8 korp. 1 ul.Stroitelei, Moscow 119311, Russia;
(22)
d.70 ul.Gertsena, Tyumen, Tyumenskaya obl. 625000, Russia;
(23)
d. 13 str. 3 ul.Bolshaya Cheremushkinskaya, Moscow 117447, Russia;
(24)
d. 6 litera D ul.Startovaya, St. Petersburg 196210, Russia;
(25)
Sosenskoe Pos, Pos. Gazoprovod, D. 101 Korp. 9, Moscow 142770, Russia;
(26)
8 Korp. 1 ul.Stroitelei, Moscow 119991, Russia;
(27)
d. Dom 24 korp. Liter A nab.Admirala Lazareva, St. Petersburg 197110, Russia;
(28)
d.16 ul.Ostrovskogo, Surgut, Khanty-Mansiski Avtonomny okrug—Yugra a.o. 628417, Russia;
(29)
16, Gsp-7 ul.Nametkina, Moscow 117997, Russia;
(30)
d. 6 ul.Nametkina, Moscow 117420, Russia;
(31)
3 korp.2 ul.Varshavskaya, St. Petersburg 196128, Russia;
(32)
d. 20 litera A nab.Aptekarskaya, St. Petersburg 197022, Russia;
(33)
d.16 ul.Nametkina, Moscow 117997, Russia;
(34)
d. 62 str. 2 shosse Starokaluzhskoe, Moscow 117630, Russia;
(35)
d.41 ul.Adelya Kutuya, Kazan, Tatarstan resp 420073, Russia;
(36)
d.36 ul.Im Dzerzhinskogo, Krasnodar, Krasnodarski krai 350051, Russia;
(37)
ul.O.Bulacha, Makhachkala, Dagestan resp. 367030, Russia;
(38)
d.11 ul.Zvezdinka, Nizhni Novgorod, Nizhegorodskaya obl. 603950, Russia;
(39)
d. 106 A str. 1 ul.Novo-Sadovaya, Samara, Samarskaya obl. 443068, Russia;
(40)
3 korp.2 ul.Varshavskaya, St. Petersburg 196128, Russia;
(41)
d.118 A prospekt Im 50 Let Oktyabrya, Saratov, Saratovskaya obl. 410052, Russia;
(42)
d.6 prospekt Oktyabrskoi Revolyutsii, Stavropol, Stavropolski krai 355000, Russia;
(43)
d.1 ul.Universitetskaya, Surgut, Khanty-Mansiski Avtonomny okrug—Yugra a.o. 628406, Russia;
(44)
d.9 prospekt Frunze, Tomsk, Tomskaya obl. 634029, Russia;
(45)
59 ul.Rikharda Zorge, Ufa, Bashkortostan resp. 450054, Russia;
(46)
d.39/2 prospekt Lenina, Ukhta, Komi resp 169312, Russia;
(47)
58 ul.Raboche-Krestyanskaya, Volgograd, Volgogradskaya obl. 400074, Russia;
(48)
d.15 ul.Mira, Yugorsk, Khanty-Mansiski Avtonomny okrug, Yugra a.o. 628260, Russia;
(49)
d.1 ul.Moskovskaya, Shchelkovo, Moskovskaya obl 141112, Russia;
(50)
P Razvilka, Leninski Raion, Moskovskaya obl. 142717, Russia;
(51)
Dom 4, Stroennie 3, Proezd 4806, Zelenograd, Russia 124460;
(52)
(53)
(54)
1st Zapadny Proezd 12/1, Zelenograd, Russia 124460;
(55)
(56)
(57)
d.19 ul.Pogranichnaya, Petropavlovsk-Kamchatski, Kamchatski krai 683032, Russia;
(58)
d.1 pl.Akademika Kurchatova, Moscow 123182, Russia;
(59)
d.103 prospekt Kurortny, Sochi, Krasnodarski krai 354024, Russia;
(60)
Rakhmanovskiy lane, 4, bld.1, Morskoy House, Moscow 127994, Russia;
(61)
d. 20 korp. 8 ul. Staraya Basmannaya, Moscow 107066, Russia;
(62)
(63)
12, proyezd Mashinostroiteley, Severodvinsk, Arkhangelskaya Oblast 164509, Russia (See alternate address in Crimea region of Ukraine).
(64)
Rakhmanovskiy lane, 4, bld.1, Morskoy House, Moscow 127994, Russia;
(65)
Stroitelnaya Street, 34, village of Kesova Gora, Tver Oblast 171470, Russia;
(66)
Street Zastavskaya Building 22, Part A, Saint Petersburg 196084, Russia;
(67)
6 Barklaya str., bld. 5, Moscow 121087, Russia;
(68)
Russia;
(69)
d. 10 korp. 3 ul. Neverovskogo, Moscow 121170, Russia;
(70)
Anapskoye Highway 1, Temryuk, Russia (See alternate address under Crimea region of Ukraine);
(71)
Dobroslobodskaya, 3 BC Basmanov, Moscow 105066, Russia.
(72)
Rakhmanovskiy lane, 4, bld.1, Morskoy House, Moscow 127994, Russia;
(73)
(74)
d.73 ul.Bolshaya Podgornaya, Tomsk, Tomskaya obl. 634009, Russia;
(75)
d. 41 korp. 1 prospekt Vernadskogo, Moscow 117415, Russia.
Although the Export Administration Act expired on August 20, 2001, the President, through Executive Order 13222 of August 17, 2001, 3 CFR, 2001 Comp., p. 783 (2002), as amended by Executive Order 13637 of March 8, 2013, 78 FR 16129 (March 13, 2013) and as extended by the Notice of August 4, 2016, 81 FR 52587 (August 8, 2016), has continued the Export Administration Regulations in effect under the International Emergency Economic Powers Act. BIS continues to carry out the provisions of the Export Administration Act, as appropriate and to the extent permitted by law, pursuant to Executive Order 13222, as amended by Executive Order 13637.
1. Executive Orders 13563 and 12866 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. This rule has been determined to be not significant for purposes of Executive Order 12866.
2. Notwithstanding any other provision of law, no person is required to respond to nor be subject to a penalty for failure to comply with a collection of information, subject to the requirements of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
Total burden hours associated with the PRA and OMB control number 0694-0088 are not expected to increase as a result of this rule. You may send comments regarding the collection of information associated with this rule, including suggestions for reducing the burden, to Jasmeet K. Seehra, Office of Management and Budget (OMB), by email to
3. This rule does not contain policies with Federalism implications as that term is defined in Executive Order 13132.
4. The provisions of the Administrative Procedure Act (5 U.S.C. 553) requiring notice of proposed rulemaking, the opportunity for public comment and a delay in effective date are inapplicable because this regulation involves a military or foreign affairs function of the United States. (
Exports, Reporting and recordkeeping requirements, Terrorism.
For the reasons stated in the preamble, the Bureau of Industry and Security amends part 744 of the Export Administration Regulations (15 CFR parts 730-774) as follows:
50 U.S.C. 4601
The additions read as follows:
Office of Surface Mining Reclamation and Enforcement, Interior.
Decision on petition for rulemaking.
We, the Office of Surface Mining Reclamation and Enforcement (OSMRE), are announcing our final decision on a petition for rulemaking that was submitted by WildEarth Guardians. The petition requested that we revise our current regulations to better ensure that self-bonded companies provide sufficient information to guarantee that reclamation obligations are adequately met and that the self-bonded entity is financially solvent. The Director has decided to grant the petition, although we do not intend to propose the specific rule changes requested in the petition. We will initiate a rulemaking to address this issue as discussed more fully below.
September 7, 2016.
Copies of the petition and other relevant materials comprising the
Michael Kuhns, Division of Regulatory Support, 1951 Constitution Ave. NW., Washington, DC 20240; Telephone: 202-208-2860; Email:
On March 3, 2016, we received a petition from WildEarth Guardians (petitioner) requesting that OSMRE amend its self-bonding regulations at 30 CFR 800.23 to ensure that companies with a history of financial insolvency, and their subsidiary companies, are not allowed to self-bond coal mining operations. WildEarth Guardians submitted this petition pursuant to section 201(g) of the Surface Mining Control and Reclamation Act of 1977 (SMCRA), 30 U.S.C. 1201(g), which provides that any person may petition the Director of OSMRE to initiate a proceeding for the issuance, amendment, or repeal of any regulation adopted under SMCRA. OSMRE adopted regulations at 30 CFR 700.12 to implement this statutory provision.
In accordance with our regulation at 30 CFR 700.12(c), we determined that WildEarth Guardians' petition set forth “facts, technical justification and law” establishing a “reasonable basis” for amending our regulations. Therefore, on May 20, 2016, we published a document in the
After reviewing the petition and public comments, the Director has decided to grant WildEarth Guardians' petition. Pursuant to 5 U.S.C. 553(e) and section 201(c)(2) of SMCRA, 30 U.S.C. 1211(c)(2), we plan to initiate rulemaking and publish a notice of proposed rulemaking with an appropriate public comment period. Although we are still considering the content of the proposed rule, we expect that it will contain updates and improvements to our regulations to ensure that reclamation obligations are adequately met and that any self-bonded entity is financially solvent. However, OSMRE does not intend to propose the petitioner's suggested rule language because it did not address important issues such as the process for evaluating applications for self-bonds, monitoring the financial health of self-bonded entities, and providing a mechanism for replacing self-bonds with other types of financial assurances if the need arises.
The WildEarth Guardians' petition for rulemaking requests that OSMRE amend its self-bonding regulations at 30 CFR 800.23 to ensure that companies with a history of financial insolvency, and their subsidiary companies, are not allowed to self-bond coal mining operations. The petition claims that current rules allow regulatory authorities (RAs) to accept self-bond guarantees from subsidiary companies that are technically insolvent due to the financial status of their parent corporations, potentially shifting the financial burden for substantial mine reclamation costs to American taxpayers in the event the companies do not have the financial resources to complete their mine reclamation obligations.
In its petition, WildEarth Guardians provides draft regulatory language that it alleges will ensure that any entity, including non-parent corporate guarantors, will be subject to appropriate financial scrutiny before being allowed to self-bond. Specifically, WildEarth Guardians requests that we revise our self-bonding regulations to define the term “ultimate parent corporation,” limit the total amount of present and proposed self-bonds to not exceed twenty-five (25) percent of the ultimate parent corporation's tangible net worth in the United States, and require that both the self-bonding applicant and its parent corporation meet any self-bonding financial conditions in 30 CFR 800.23, including the requirement that neither have filed for bankruptcy in the last five (5) years.
Our current regulations at 30 CFR 800.23 set minimum standards for accepting a self-bond from an applicant. Paragraph (a) provides definitions for the terms “current assets,” “current liabilities,” “fixed assets,” “liabilities,” “net worth,” “parent corporation,” and “tangible net worth.” Paragraph (b) sets out the conditions that an applicant must meet before it can be eligible to self-bond. The applicant must designate a suitable agent to receive service of process, paragraph (b)(1); demonstrate continuous operation as a business entity for at least 5 years, paragraph (b)(2); submit financial information satisfying at least one of three financial tests, paragraph (b)(3); and submit various audited and unaudited financial statements, paragraph (b)(4). Paragraph (c) allows an RA to accept a written guarantee for an applicant's self-bond from a parent or “corporate” guarantor as long as the guarantor meets the conditions of paragraphs (b)(1) and (b)(4) of 30 CFR 800.23 and sets out the terms for a corporate guarantee. Paragraph (d) states that, in order for an RA to accept an applicant's self-bonds, the total amount of the outstanding and proposed self-bonds of the applicant must not exceed twenty-five (25) percent of the applicant's tangible net worth in the United States. Paragraph (e) provides the requirements for any indemnity agreements. Paragraph (f) allows an RA to require self-bonded applicants, parent and non-parent corporate guarantors to submit an update of the information required under paragraphs (b)(3) and (b)(4) of this section within 90 days after the close of each fiscal year following the issuance of the self-bond or corporate guarantee. Finally, paragraph (g) requires that, if at any time during the period when a self-bond is posted, the financial conditions of the applicant, parent or non-parent corporate guarantor change so that the criteria of paragraphs (b)(3) and (d) are not satisfied, the permittee must notify the RA and, within 90 days, post an alternate form of bond in the same amount as the self-bond. This paragraph also provides that if the permittee fails to post an adequate substitute bond, the regulatory provisions of § 800.16(e), addressing bond procedures in the event of bankruptcy or insolvency, will apply.
We received 117,191 comments on the petition for rulemaking. These comments can be divided into two major groups: those in favor of the rulemaking (over 99%) and those opposed (less than 1%, or fourteen unique comments).
Supporters of the petition expressed concern that the current self-bond
Opponents of rulemaking asserted that most coal companies have a history of solvency and that even those companies currently in bankruptcy have continued to meet their reclamation obligations. Commenters also stated that they believed SMCRA and OSMRE's implementing regulations at 30 CFR 800.23 already provide adequate criteria for self-bonding and that the language proposed by petitioners would violate section 525 of the federal bankruptcy code, 11 U.S.C. 525(a), by discriminating against bankrupt entities. Commenters also expressed concern that more stringent self-bonding regulations would unnecessarily limit the flexibility of state RAs in determining whether to allow self-bonding. They assert that this would simply shift reclamation liability from one type of bonding instrument (self-bonding) to another (surety, letter of credit, collateral, or some other financial assurance), which the commenters allege would exacerbate current stresses on the coal market. Several commenters requested that OSMRE deny the petition and allow additional time for us to work with the Interstate Mining Compact Commission and state regulatory authorities to find a non-regulatory solution to the self-bonding problem.
After reviewing the petition and supporting materials, and after careful consideration of all comments received, OSMRE has decided to grant the petition. However, we do not plan to propose adoption of the specific regulatory changes suggested by the petitioner. Instead, we are examining broader regulatory changes to 30 CFR part 800 to update OSMRE's bonding regulations and ensure the completion of the reclamation plan if the regulatory authority has to perform the work in the event of forfeiture.
It is undisputed that the coal market is dramatically different from when our current self-bonding regulations were drafted. Diminished global demand for coal, competition from low cost shale gas, and the unprecedented and continuing retirement of coal-fired power plants are clear signs that the energy industry is undergoing a major transformation. It is incumbent upon OSMRE to protect the public's interests in connection with self-bonding. Without a rigorous financial investigation, both before accepting self-bond and throughout the duration of a self-bond, it is impossible to ensure that the public will be adequately protected from the risk that a self-bonded entity will have insufficient funds to complete all of the required reclamation.
During our evaluation of the petition and the comments, we discovered instances where self-bond applicants did not provide sufficient financial information for state RAs to make informed decisions about whether that applicant was financially stable enough to self-bond. We also discovered that, because the financial condition of some companies changed so quickly, state RAs have experienced difficulties requesting and/or receiving additional financial information from a self-bonded entity when the RA becomes aware that the financial situation of that entity has changed, and enforcing the requirement that a self-bonded entity notify the RA and obtain replacement bond when it no longer qualifies for self-bonding under the regulations. Our current regulations look at companies' historical performance in order to assess their future solvency instead of using criteria that are more forward looking. For example, some companies qualified for self-bonding just months before the company declared bankruptcy, in part by providing year-old financial data that did not reflect the dramatic changes in the coal market and the declining financial health of those self-bonded entities in the intervening year. In other instances, the financial information came too late or too slowly for RAs to take enforcement action before the company declared bankruptcy. Once a self-bonded company files for bankruptcy, obtaining replacement bonds becomes significantly more difficult. We have concluded that the current regulations do not require use of the most appropriate financial tests, both before a self-bond is approved and during the life of a self-bond.
In light of these findings, OSMRE will consider proposing a number of changes to our regulations. We anticipate reviewing the definitions in 30 CFR 800.23(a), as well as reviewing the existing financial tests and documentation required under 30 CFR 800.23(b), to ensure that the self-bond applicant is financially stable. We also will consider developing a systematic review process for ascertaining whether self-bonded entities remain financially healthy and for spotting any adverse trends that might necessitate replacing a self-bond with a different type of financial assurance. We will also consider if we need to provide an independent third party review of the self-bonding entity's annual financial reports and certification of the current and future financial ability of the self-bonding entity. Lastly, we may propose additional procedures for replacing self-bonds in the event that a company no longer meets the financial tests and to clarify the penalties for an entity's failure to disclose a change in financial status.
As mentioned above, we may also propose revisions to other bonding requirements, and explore the possibility of the creation of new financial assurance instruments to provide industry more options. We will likely explore the potential of requiring diversified financial assurances. Relying on just one type of financial assurance, such as self-bond or a surety bond from just one company, could be risky in an uncertain financial market. We are also likely to explore ways to make sure there is sufficient collateral to cover all reclamation obligations. Under our current regulations, the same small set of assets has been used as collateral for multiple liabilities. In a number of cases, the aggregate amount of these liabilities has been far greater than the value of the assets used as collateral, with the result that reclamation obligations are at risk of not being met. We will explore ways to address this problem, such as assessing the merits of requiring that a percentage of all bonds be supported by collateral that is not subject to any other lien nor used as collateral for any other mine or other liability. In addition, we need to explore the possibility of establishing criteria to create a greater incentive for self-bonded companies to timely complete reclamation and apply for final bond release. Companies that have surety bonds either pay a fee for the bond or have some sort of collateral that is being held by the surety company. These frozen assets give them an incentive to complete reclamation that self-bonded companies do not have. Finally, we will examine concerns raised over certain
We believe that carefully considered revisions to our regulations will better (1) ensure the completion of the reclamation plan as required in section 509(a) of SMCRA, 30 U.S.C. 1259(a), (2) guarantee that an applicant demonstrates a history of financial solvency and continuous operation sufficient for authorization to self-insure as required in section 509(c) of SMCRA, 30 U.S.C. 1259(c), and (3) assure that surface coal mining operations are conducted to protect the environment, 30 U.S.C. 1202(d).
As we begin to examine broader regulatory changes, we will seek specific input from the many stakeholders about their ideas of how to improve our regulations. The state RAs have many years of experience with self-bonding and we will ask that they provide specific suggestions on how to improve our regulations to ensure they have adequate financial assurance to complete reclamation of each mine.
This document is not a proposed or final rule, policy, or guidance. Therefore, it is not subject to the Regulatory Flexibility Act, the Small Business Regulatory Enforcement Fairness Act, the Paperwork Reduction Act, the Unfunded Mandates Reform Act, or Executive Orders 12866, 13563, 12630, 13132, 12988, 13175, and 13211. We will conduct the analyses required by these laws and executive orders when we develop a proposed rule.
In developing this document, we did not conduct or use a study, experiment, or survey requiring peer review under the Information Quality Act (Pub. L. 106-554, section 15).
This document is not subject to the requirement to prepare an Environmental Assessment or Environmental Impact Statement under the National Environmental Policy Act (NEPA), 42 U.S.C. 4332(2)(C), because no proposed action, as described in 40 CFR 1508.18(a) and (b), yet exists. This document only announces the Director's decision to grant a petition and initiate rulemaking. We will prepare the appropriate NEPA compliance documents as part of the rulemaking process.
Under Secretary of Defense for Personnel and Readiness, DoD.
Final rule; technical amendment.
On January 25, 2016, the Department of Defense published a final rule, 81 FR 3959-3962, titled Professional U.S. Scouting Organization Operations at U.S. Military Installations Overseas. DoD is making a technical amendment due to the discovery of a mistake regarding the use of nonappropriated funds. A paragraph in the final rule incorrectly stated nonappropriated funds cannot be used to reimburse salaries and benefits of qualified scouting organization employees. Nonappropriated funds may be used to reimburse salaries and benefits of employees of qualified scouting organizations for periods during which their professional scouting employees perform services in overseas areas in direct support of DoD personnel and their families.
This rule is effective September 7, 2016.
Ms. Patricia Toppings, 571-372-0485.
This technical amendment amends 32 CFR part 252 to read as set forth in the amendatory language in this final rule.
Military installations, Military personnel, Scout organizations.
Accordingly 32 CFR part 252 is amended as follows:
E.O. 12715, May 3, 1990, 55 FR 19051; 10 U.S.C. 2606, 2554, and 2555.
(a) * * *
(6) * * *
(i) APF is not used to reimburse their salaries and benefits.
Coast Guard, DHS.
Notice of deviation from drawbridge regulation.
The Coast Guard has issued a temporary deviation from the operating schedule that governs the Montlake Bridge across the Lake Washington Ship Canal, mile 5.2, at Seattle, WA. The Montlake Bridge is a double leaf bascule bridge. The deviation is necessary to allow work crews to replace bridge decking. This deviation allows a single leaf opening with a one hour advance notice during the day, and remains in the closed-to-navigation position at night.
This deviation is effective from 6 a.m. on September 24, 2016 to 6 a.m. on September 26, 2016.
The docket for this deviation, [USCG-2016-0847] is available at
If you have questions on this temporary deviation, call or email Mr. Steven Fischer, Bridge Administrator, Thirteenth Coast Guard District; telephone 206-220-7282, email
Washington Department of Transportation has requested a temporary deviation from the operating schedule for the Montlake Bridge across the Lake Washington Ship Canal, at mile 5.2, at Seattle, WA. The deviation is necessary to accommodate work crews to conduct timely bridge deck
The deviation period is from 6 a.m. until 6 p.m. on September 24, 2016 (north single leaf opening if a one hour notice is given); from 6 p.m. on September 24, 2016 until 6 a.m. on September 25, 2016 (span remain in the closed-to-navigation position); from 6 a.m. until 6 p.m. on September 25, 2016 (north single leaf opening if a one hour notice is given); from 6 p.m. on September 25, 2016 until 6 a.m. on September 26, 2016 (span remain in the closed-to-navigation position). The normal operating schedule for the Montlake Bridge operates in accordance with 33 CFR 117.1051(e).
Waterway usage on the Lake Washington Ship Canal ranges from commercial tug and barge to small pleasure craft. Vessels able to pass through the bridge in the closed-to-navigation position may do so at any time. The bridge will be able to open for emergency vessels in route to a call when an hour notice is given to the bridge operator, and a single leaf opening will be provided. The Lake Washington Ship Canal has no immediate alternate route for vessels to pass. The Coast Guard will also inform the users of the waterways through our Local and Broadcast Notices to Mariners of the change in operating schedule for the bridge so that vessels can arrange their transits to minimize any impact caused by the temporary deviation.
In accordance with 33 CFR 117.35(e), the drawbridge must return to its regular operating schedule immediately at the end of the designated time period. This deviation from the operating regulations is authorized under 33 CFR 117.35.
Coast Guard, DHS.
Notice of enforcement of regulation.
The Coast Guard will enforce safety zone regulations for a fireworks display taking place offshore the Virginia Beach oceanfront in the vicinity of the 20th Street, Virginia Beach, VA, on October 1, 2016. This action is necessary to ensure safety of life on navigable waters during this event. Our regulation for Recurring Marine Events within the Fifth Coast Guard District identifies the regulated area for this fireworks display event. During the enforcement period, no person or vessel may enter, transit through, anchor in, or remain within the regulated area without approval from the Captain of the Port Hampton Roads or a designated representative.
From 8:30 p.m. through 10 p.m. on October 1, 2016, the regulations in 33 CFR 165.506 will be enforced for the safety zone regulated area listed in row (c) 9 of the table to § 165.506.
If you have questions about this notice of enforcement, call or email ENS Chandra Saunders, U.S. Coast Guard Sector Hampton Roads (WWM); telephone 757-668-5582, email
The Coast Guard will enforce the safety zone regulations in 33 CFR 165.506 from 8:30 p.m. until 10 p.m. on October 1, 2016, for the safety zone regulated area listed in row (c) 9 of the table to § 165.506. This enforcement is related to a fireworks display that is part of the Virginia Beach Neptune Festival, on the North Atlantic Ocean, Virginia Beach, VA. This action is being taken to provide for the safety of life on navigable waterways during this event.
Our regulation for Recurring Marine Events within the Fifth Coast Guard District, § 165.506, specifies the location of the regulated area for this safety zone within a 1000 yard radius of the center located near the shoreline at approximate position latitude 36°51′12″ N., longitude 075°58′06″ W., located off Virginia Beach, VA between 17th and 31st streets. As specified in § 165.506 (d), during the enforcement period, no vessel may not enter, remain in, or transit through the safety zone without approval from the Captain of the Hampton Roads (COTP) or a COTP designated representative. The Coast Guard may be assisted by other Federal, state or local law enforcement agencies in enforcing this regulation.
This notice of enforcement is issued under authority of 33 CFR 165.506(d) and 5 U.S.C. 552 (a). In addition to this notice of enforcement in the
Coast Guard, DHS.
Notice of enforcement of regulation.
The Coast Guard will enforce a safety zone for the Pittsburgh Pirates Fireworks on the Allegheny River, from mile 0.2 to 0.8, to protect vessels transiting the area and event spectators from the hazards associated with the Pittsburgh Pirates land-based fireworks displays following certain home games throughout the season. During the enforcement period, entry into, transiting, or anchoring in the safety zone is prohibited to all vessels not registered with the sponsor as participants or official patrol vessels, unless specifically authorized by the Captain of the Port (COTP) Pittsburgh or a designated representative.
The regulations in 33 CFR 165.801 Table 1, Sector Ohio Valley, No. 1 will be enforced from 8:00 p.m. until 11:30 p.m., on September 10, 2016 with a rain date to occur within 48 hours of the scheduled date.
If you have questions about this notice of enforcement, call or email MST1
The Coast Guard will enforce the Safety Zone for the annual Pittsburgh Pirates Fireworks listed in 33 CFR 165.801 Table 1, Sector Ohio Valley, No. 1 from 8:00 p.m. to 11:30 p.m. on September 10, 2016. Should inclement weather require rescheduling, the safety zone will be within 48 hours of the scheduled date. Entry into the safety zone is prohibited unless authorized by the COTP or a designated representative. Persons or vessels desiring to enter into or passage through the safety zone must request permission from the COTP or a designated representative. If permission is granted, all persons and vessels shall comply with the instructions of the COTP or designated representative.
This notice of enforcement is issued under authority of 33 CFR 165.801 and 5 U.S.C. 552(a). In addition to this notice in the
Environmental Protection Agency (EPA).
Final rule.
This regulation establishes tolerances for residues of chlorantraniliprole in or on multiple commodities which are identified and discussed later in this document. Interregional Research Project Number 4 (IR-4) requested the tolerances under the Federal Food, Drug, and Cosmetic Act (FFDCA).
This regulation is effective September 7, 2016. Objections and requests for hearings must be received on or before November 7, 2016, and must be filed in accordance with the instructions provided in 40 CFR part 178 (see also Unit I.C. of the
The docket for this action, identified by docket identification (ID) number EPA-HQ-OPP-2013-0235, is available at
Michael Goodis, Registration Division (7505P), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460-0001; main telephone number: (703) 305-7090; email address:
You may be potentially affected by this action if you are an agricultural producer, food manufacturer, or pesticide manufacturer. The following list of North American Industrial Classification System (NAICS) codes is not intended to be exhaustive, but rather provides a guide to help readers determine whether this document applies to them. Potentially affected entities may include:
• Crop production (NAICS code 111).
• Animal production (NAICS code 112).
• Food manufacturing (NAICS code 311).
• Pesticide manufacturing (NAICS code 32532).
You may access a frequently updated electronic version of EPA's tolerance regulations at 40 CFR part 180 through the Government Printing Office's e-CFR site at
Under FFDCA section 408(g), 21 U.S.C. 346a, any person may file an objection to any aspect of this regulation and may also request a hearing on those objections. You must file your objection or request a hearing on this regulation in accordance with the instructions provided in 40 CFR part 178. To ensure proper receipt by EPA, you must identify docket ID number EPA-HQ-OPP-2013-0235 in the subject line on the first page of your submission. All objections and requests for a hearing must be in writing, and must be received by the Hearing Clerk on or before November 7, 2016. Addresses for mail and hand delivery of objections and hearing requests are provided in 40 CFR 178.25(b).
In addition to filing an objection or hearing request with the Hearing Clerk as described in 40 CFR part 178, please submit a copy of the filing (excluding any Confidential Business Information (CBI)) for inclusion in the public docket. Information not marked confidential pursuant to 40 CFR part 2 may be disclosed publicly by EPA without prior notice. Submit the non-CBI copy of your objection or hearing request, identified by docket ID number EPA-HQ-OPP-2013-0235, by one of the following methods:
•
•
•
In the
A comment was received on the notice of filing. EPA's response to this comment is discussed in Unit IV.C.
Section 408(b)(2)(A)(i) of FFDCA allows EPA to establish a tolerance (the legal limit for a pesticide chemical residue in or on a food) only if EPA determines that the tolerance is “safe.” Section 408(b)(2)(A)(ii) of FFDCA defines “safe” to mean that “there is a reasonable certainty that no harm will result from aggregate exposure to the pesticide chemical residue, including all anticipated dietary exposures and all other exposures for which there is reliable information.” This includes exposure through drinking water and in residential settings, but does not include occupational exposure. Section 408(b)(2)(C) of FFDCA requires EPA to give special consideration to exposure of infants and children to the pesticide chemical residue in establishing a tolerance and to “ensure that there is a reasonable certainty that no harm will result to infants and children from aggregate exposure to the pesticide chemical residue. . . .”
Consistent with FFDCA section 408(b)(2)(D), EPA has reviewed the available scientific data and other relevant information in support of this action. EPA has sufficient data to assess the hazards of and to make a determination on aggregate exposure for chlorantraniliprole in or on teff forage, grain, hay and straw as well as quinoa forage, grain, hay and straw, consistent with FFDCA section 408(b)(2).
In the
The Agency evaluated the request to establish tolerances in or on quinoa and teff forage, grain, hay, and straw and concluded that the aggregate exposure and risks would not increase as a result of the proposed use on quinoa and teff and are the same as those estimated in the February 7, 2014 final rule.
Both quinoa and teff are prepared like other whole grains, such as rice and barley, and may also be used to make flour in a manner similar to wheat and other cereal grains. Therefore, EPA concludes that teff and quinoa will likely substitute in the diet for cereal grain foods, which are subject to tolerances for chlorantraniliprole, and would be assumed to contain similar residues. Additionally, since teff and quinoa use patterns are similar to those for wheat and barley, increased exposures to individuals through drinking water is not expected. Thus, the proposed teff and quinoa uses will not result in higher dietary exposure estimates.
With respect to livestock commodities, residues of chlorantraniliprole in teff and quinoa livestock feeds are expected to be similar to those in other forages, hays, and silages for which chlorantraniliprole is currently registered. Therefore, there would be no increase in the livestock dietary burden should teff and quinoa be substituted in the livestock diet for other hays and silages; residues in meat, milk, poultry and eggs will remain the same.
EPA concludes that the aggregate exposure and risk estimates presented in the most recent human health risk assessment document, which were not of concern to the Agency, adequately account for exposures and risk resulting from all chlorantraniliprole uses including the proposed teff and quinoa uses.
Therefore, EPA relies upon the findings made in the February 7, 2014
For a detailed discussion of the aggregate risk assessments and determination of safety for these tolerances, please refer to the February 7, 2014
Adequate enforcement methodology, liquid chromatography mass spectrometry/mass spectrometry (LC/MS/MS); Method DuPont-11374, is available to enforce the tolerance expression.
The method may be requested from: Chief, Analytical Chemistry Branch, Environmental Science Center, 701 Mapes Rd., Ft. Meade, MD 20755-5350; telephone number: (410) 305-2905; email address:
In making its tolerance decisions, EPA seeks to harmonize U.S. tolerances with international standards whenever possible, consistent with U.S. food safety standards and agricultural practices. EPA considers the international maximum residue limits (MRLs) established by the Codex Alimentarius Commission (Codex), as required by FFDCA section 408(b)(4). The Codex Alimentarius is a joint United Nations Food and Agriculture Organization/World Health Organization food standards program, and it is recognized as an international food safety standards-setting organization in trade agreements to which the United States is a party. EPA may establish a tolerance that is different from a Codex MRL; however, FFDCA section 408(b)(4) requires that EPA explain the reasons for departing from the Codex level.
There are no Codex MRLs for chlorantraniliprole residues in or on quinoa or teff.
EPA received one comment to the Notice of Filing that stated, in part, that this chemical is “dangerous to America and to health of our people and life in America” and that EPA should “deny those applications from the profiteers whose only aim is to make money at our expense.” The Agency understands the commenter's concerns and recognizes that some individuals believe that pesticides should be banned on agricultural crops. However, the existing legal framework provided by section 408 of the FFDCA states that tolerances may be set when persons seeking such
Therefore, tolerances are established for residues of chlorantraniliprole, 3-bromo-
This action establishes tolerances under FFDCA section 408(d) in response to a petition submitted to the Agency. The Office of Management and Budget (OMB) has exempted these types of actions from review under Executive Order 12866, entitled “Regulatory Planning and Review” (58 FR 51735, October 4, 1993). Because this action has been exempted from review under Executive Order 12866, this action is not subject to Executive Order 13211, entitled “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001) or Executive Order 13045, entitled “Protection of Children from Environmental Health Risks and Safety Risks” (62 FR 19885, April 23, 1997). This action does not contain any information collections subject to OMB approval under the Paperwork Reduction Act (PRA) (44 U.S.C. 3501
This action directly regulates growers, food processors, food handlers, and food retailers, not States or tribes, nor does this action alter the relationships or distribution of power and responsibilities established by Congress in the preemption provisions of FFDCA section 408(n)(4). As such, the Agency has determined that this action will not have a substantial direct effect on States or tribal governments, on the relationship between the national government and the States or tribal governments, or on the distribution of power and responsibilities among the various levels of government or between the Federal Government and Indian tribes. Thus, the Agency has determined that Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999) and Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (65 FR 67249, November 9, 2000) do not apply to this action. In addition, this action does not impose any enforceable duty or contain any unfunded mandate as described under Title II of the Unfunded Mandates Reform Act (UMRA) (2 U.S.C. 1501
This action does not involve any technical standards that would require Agency consideration of voluntary consensus standards pursuant to section 12(d) of the National Technology Transfer and Advancement Act (NTTAA) (15 U.S.C. 272 note).
Pursuant to the Congressional Review Act (5 U.S.C. 801
Environmental protection, Administrative practice and procedure, Agricultural commodities, Pesticides and pests, Reporting and recordkeeping requirements.
Therefore, 40 CFR chapter I is amended as follows:
21 U.S.C. 321(q), 346a and 371.
(a) * * *
Environmental Protection Agency (EPA).
Final rule and technical amendment.
The Environmental Protection Agency (EPA) is approving a modification of the ocean dredged material disposal site (ODMDS) offshore of Charleston, South Carolina pursuant to the Marine Protection, Research and Sanctuaries Act, as amended (MPRSA). The primary purpose for the site modification is to serve the long-term need for a location to dispose of material dredged from the Charleston Harbor federal navigation channel, and to provide a location for the disposal of dredged material for persons who have received a permit for such disposal. The modified site will be subject to ongoing monitoring and management to ensure continued protection of the marine environment. In addition, the EPA now issues a technical amendment to correct a clerical error in the proposed rule.
The effective date of this final action shall be October 7, 2016.
Gary W. Collins, U.S. Environmental Protection Agency, Region 4, Water Protection Division, Marine Regulatory and Wetlands Enforcement Section, 61 Forsyth Street, Atlanta, Georgia 30303; phone number (404) 562-9395; email:
Persons potentially affected by this action include those who seek or might seek permits or approval to dispose of dredged material into ocean waters pursuant to the Marine Protection, Research, and Sanctuaries Act, as amended (MPRSA), 33 U.S.C. 1401 to 1445. The EPA's action would be relevant to persons, including organizations and government bodies seeking to dispose of dredged material in ocean waters offshore of Charleston, South Carolina. Currently, the U.S. Army Corps of Engineers (USACE) would be most affected by this action. Potentially affected categories and persons include:
This table is not intended to be exhaustive, but rather provides a guide for readers regarding persons likely to be affected by this action. For any questions regarding the applicability of this action to a particular person, please refer to the contact person listed in the preceding
The existing Charleston ODMDS is located approximately 9 nautical miles (nmi) southeast of the mouth of Charleston Harbor on the continental shelf off the coast of South Carolina. It is currently 12.1 nmi
The USACE Charleston District and the EPA Region 4 have identified a need to either designate a new ODMDS or expand the existing Charleston ODMDS. The need for expanding current ocean disposal capacity is based on future capacity modeling, historical dredging volumes, estimates of dredging volumes for future proposed projects, and limited capacity of upland confined disposal facilities (CDFs) in the area.
The modification of the ODMDS for dredged material does not mean that the USACE or the EPA has approved the use of the ODMDS for open water disposal of dredged material from any specific project. Before any person can dispose dredged material at the ODMDS, the EPA and the USACE must evaluate the project according to the ocean dumping regulatory criteria (40 CFR, part 227) and authorize the disposal. The EPA independently evaluates proposed dumping and has the right to restrict and/or disapprove of the actual disposal of dredged material if the EPA determines that environmental requirements under the MPRSA have not been met.
This action modifies the ODMDS offshore of Charleston, South Carolina. The location of the modified ODMDS is bounded by the coordinates, listed below. The modification of the ODMDS will allow the EPA to adaptively manage the ODMDS to maximize its capacity, minimize the potential for mounding and associated safety concerns, potentially create hard bottom habitat and minimize the potential for any long-term adverse effects to the marine environment.
The coordinates for the site are, in North American Datum 83 (NAD 83):
The modified ODMDS is located in approximately 30 to 45 feet of water, and is located to approximately 6.0 nmi offshore. The modified ODMDS would be 7.4 nmi
On July 13, 2016, the EPA published a proposed rule to modify the site and opened a public comment period under Docket ID No. EPA-R04-OW-2016-0356. The comment period ended on August 12, 2016. The EPA received two comments on the proposed rule. One comment was from the U.S. Department of Interior stating that they had no comments at this time. The second comment was from the U.S. National Oceanic and Atmospheric Administration in regards to a clerical error with three site coordinates describing the location of the ODMDS. The EPA acknowledges the error and is making corrections as described in the technical amendment section below.
The modified ODMDS is expected to receive sediments dredged by the USACE to deepen and maintain the federally authorized navigation project at Charleston Harbor, South Carolina, and dredged material from other persons who have obtained a permit for the transportation of dredged material
In modifying the ODMDS, the EPA assessed the modified ODMDS according to the criteria of the MPRSA, with particular emphasis on the general and specific regulatory criteria of 40 CFR part 228, to determine whether the site modification satisfies those criteria. The EPA's
Dredged material disposal within the existing Charleston ODMDS has been confined to the eastern side of the designated site within a defined 4-mi
The ODMDS modification area will be used for disposal of suitable dredged material as determined by Section 103 of the MPRSA. Based on the USACE and EPA sediment testing and evaluation of dredged maintenance material and proposed new work material from the Post 45 deepening project, disposal is not expected to have any long-term impact on the water quality. Results of the maximum concentration found outside the disposal area after 4 hours of mixing for each dredging unit was zero. Based on these results, water quality perturbations that could reach any beach, shoreline, marine sanctuary, or known geographically-limited fishery or shellfishery are not expected. The western edge of the modified ODMDS is approximately 7 miles offshore such that prevailing current will not transport dredged material to beaches. Water quality perturbations caused by dispersion of disposal material will be reduced to ambient conditions before reaching any environmentally sensitive areas.
The location, size, and configuration of the modified ODMDS provides long-term capacity, site management, and site monitoring while limiting environmental impacts to the surrounding area. Based on 25 years of projected new work and maintenance dredged material disposal needs, it is estimated that the ODMDS modification area should accommodate approximately 66.5 mcy of dredged material in order to meet the long-term disposal needs of the area. The dump zone within the modified ODMDS is estimated to have approximately 75 mcy of capacity. The capacity in the dump zone provides a reasonable amount of additional capacity to manage risk, account for future unknown disposal operations from private entities, and provides a margin of navigation safety. The remaining area within the boundaries of the existing 12 nmi
By adding 5.8 mi
To help protect nearby hardbottom habitat from being buried by sediment migrating from the ODMDS, a U-shaped berm along the east, south, and west perimeters of the modified ODMDS will be constructed. Although there is probable hardbottom located north of the modified ODMDS, no berm will be constructed along the northern boundary. However, there will be a 3000-foot buffer along the northern perimeter of the ODMDS where dumping will not occur. Fate modeling indicates that this buffer should be sufficient to protect probable hardbottom areas to the north of the site.
When determining the size of the modified site, the ability to implement effective monitoring and surveillance programs, among other things, was factored in to ensure that navigational safety would not be compromised and to prevent mounding of dredged material, which could result in adverse wave conditions. A site management and monitoring program will be implemented to determine if disposal at the site is significantly affecting adjacent areas and to detect the presence of long-term adverse effects. At a minimum, the monitoring program will consist of bathymetric surveys, sediment grain size analysis, chemical analysis of constituents of concern in the sediments, and a health assessment of the benthic community.
The continental slope is approximately 55 nmi offshore of Charleston. Disposal off the continental shelf (shelf break) was evaluated in detail the 1983 ODMDS Designation EIS document. In comparison to locating the site in the nearshore region, it was determined that monitoring and surveillance would be more difficult and expensive in the shelf break area because of the distance from shore to the deeper waters. Transporting material to and performing long-term monitoring of a site located off the continental shelf is not economically or operationally feasible.
The historically used ocean dumping site, Charleston ODMDS, is not located beyond the continental shelf. A portion of the modified ODMDS encompasses an area previously designated for disposal.
The modified ODMDS is located on the shallow continental shelf, approximately 6 nmi offshore of Charleston, South Carolina. Water depths range from −30 to −45 feet (9 to 13 meters) with an overall average depth of −40 feet (12 meters). Characteristics of the South Atlantic Bight seafloor include low relief, relatively gentle gradients, and smooth bottom surfaces exhibiting physiographic features contoured by erosional processes. Sediments largely consist of fine to coarse sands. Some areas contain extensive coarse grains and shell hash. Fines were found to be typically less than 10%.
The modified ODMDS is not located in exclusive breeding, spawning, nursery, feeding, or passage areas for adult or juvenile phases of living resources. The intensity of these activities within the vicinity of the ODMDS is seasonally variable, with peaks typically occurring in the spring and early fall for most commercially important finfish and shellfish species (USEPA 1983). The ODMDS is not located within North Atlantic right whale critical habitat.
The center of the modified ODMDS is approximately 7 mi (6 nmi) from the nearest coastal beach. The site is approximately 3.1 mi (2.7 nmi) south of the nearest artificial reef. No significant impacts to beaches or amenity areas associated with the existing ODMDS have been documented.
Only material that meets EPA Ocean Dumping Criteria in 40 CFR 220-229 will be placed in the ODMDS. Average annual maintenance material is approximately 1.4 mcy and approximately 31.2 mcy of new work material is expected from the Charleston Harbor Deepening Project. Sediments dredged from Charleston Harbor and the entrance channel are a mixture of silt, sand, and rock. Hopper dredge, barge, and scow combinations are the usual vehicles of transport for the dredged material. None of the material is packaged in any manner.
The EPA expects monitoring and surveillance at the modified ODMDS to be feasible and readily performed from ocean or regional class research vessels. The modified ODMDS is of similar size, water depth and distance from shore as are a majority of the ODMDSs within the Southeastern United States which are routinely monitored. The EPA will ensure monitoring of the site for physical, biological and chemical attributes as well as for potential impacts beyond the site boundaries. Bathymetric surveys will be conducted routinely as defined in the SMMP, contaminant levels in the dredged material will be analyzed prior to dumping, and the benthic infauna and epibenthic organisms will be monitored every 10 years, as funding allows.
A study conducted by EPA from 2013-2015 indicated that currents in the vicinity of the Charleston ODMDS tend to have a significant tidal component with predominant currents in the cross-shore direction. The depth-averaged median current velocity was 18 cm/sec (0.6 ft/sec) with 90% of the measurements below 30 cm/sec (1.1 ft/sec). Wind-driven circulation is the most important factor in controlling sediment transport. Strong winds generate waves that steer the sediment on the seabed and create large nearbed suspended sediment concentrations. Suspended sediment transport is directed mainly NE and SW in response to local wind climate and the wind-generated alongshore flows. LTFATE and MPFATE modeling results over a 25-year period indicate depths of sediment deposited outside the boundaries of the ODMDS will not exceed the 5 cm deposition contour guidance provided by EPA.
Previous disposal of dredged material resulted in temporary increases in suspended sediment concentrations during disposal operations, localized mounding within the site, burial of benthic organisms within the site, changes in the abundance and composition of benthic assemblages, and changes in the sediment composition from sandy sediments to finer-grained silts. Impacts to live bottoms were identified in the western portion of the 12-mi
Short-term, long-term, and cumulative effects of dredged material disposal in the ODMDS modification area would be similar to those for the existing ODMDS.
The modified ODMDS is not expected to interfere with shipping, fishing, recreation or other legitimate uses of the ocean. Commercial navigation, commercial fishing, and mineral extraction (sand mining) are the primary activities that may spatially overlap with disposal at the modified ODMDS. The modified ODMDS avoids the National Oceanographic and Atmospheric Administration (NOAA) recommended vessel routes offshore Charleston, South Carolina, thereby avoiding conflict with commercial navigation.
Commercial fishing (shrimp trawling) occurs primarily to the west of the modified ODMDS. The likelihood of direct interference with these activities is low, provided there is close communication and coordination among users of the ocean resources. The EPA is not aware of any plans for desalination plants, or fish and shellfish culture operations near the modified ODMDS at this time. The modified ODMDS is not located in areas of special scientific importance.
Water quality of the existing site is typical of the Atlantic Ocean. Water and sediment quality analyses conducted in the study area and experience with past
Nuisance species, considered as any undesirable organism not previously existing at a location, have not been observed at, or in the vicinity of, the modified ODMDS. They are either transported to or recruited to the site because the disposal of dredged material creates an environment where they can establish. Habitat conditions have changed somewhat at the Charleston ODMDS because of the disposal of some silty material on what was predominately sandy sediments. While it can be expected that organisms will become established at the site which were not there previously, this new community is not regarded as a nuisance, or “undesirable,” community.
No significant cultural features have been identified at, or in the vicinity of, the modified ODMDS at this time. Surveys conducted in 2012-2013 did not identify any cultural features of historical importance. The EPA has coordinated with South Carolina's State Historic Preservation Officer (SHPO) to identify any cultural features. The SHPO concurred with the EPA's determination that the modification of the ODMDS will have no effect on cultural resources listed, or eligible for listing on the National Register of Historic Places as no such resources exist in the project area.
The EPA corrected a clerical error that was included in the proposed language regarding the modified ODMDS coordinates. The second, third, and fourth latitude coordinates were incorrect in the proposed language but have been corrected to reflect the actual corner coordinates for the modified ODMDS.
Section 102 of the National Environmental Policy Act of 1969, as amended (NEPA), 42 U.S.C. 4321 to 4370f, requires Federal agencies to prepare an Environmental Impact Statement (EIS) for major federal actions significantly affecting the quality of the human environment. NEPA does not apply to EPA designations of ocean disposal sites under the MPRSA because the courts have exempted the EPA's actions under the MPRSA from the procedural requirements of NEPA through the functional equivalence doctrine. The EPA has, by policy, determined that the preparation of NEPA documents for certain EPA regulatory actions, including actions under the MPRSA, is appropriate. The EPA's “Notice of Policy and Procedures for Voluntary Preparation of NEPA Documents,” (Voluntary NEPA Policy), 63 FR 58045, (October 29, 1998), sets out both the policy and procedures the EPA uses when preparing such environmental review documents. The EPA's primary voluntary NEPA document for expanding the ODMDS is the
The EPA integrated the essential fish habitat (EFH) assessment with the EA, pursuant to Section 305(b), 16 U.S.C. 1855(b)(2), of the Magnuson-Stevens Act, as amended (MSA), 16 U.S.C. 1801 to 1891d, and submitted that assessment to the National Marine Fisheries Service (NMFS) on December 4, 2015. The NMFS responded via letter that they have no comments on the proposed project.
Pursuant to an Office of Water policy memorandum dated October 23, 1989, the EPA has evaluated the proposed site designations for consistency with the State of South Carolina's (the State) approved coastal management program. The EPA has determined that the designation of the modified site is consistent to the maximum extent practicable with the State coastal management program, and submitted this determination to the State for review in accordance with the EPA policy. The State conditionally concurred with this determination on February 17, 2016. The EPA has taken the State's comments into account in preparing the FEA for the site, in determining whether the site should be modified as proposed, and in determining whether restrictions or limitations should be placed on the use of the site, if it is designated.
The Endangered Species Act, as amended (ESA), 16 U.S.C. 1531 to 1544, requires Federal agencies to consult with NMFS and the U.S. Fish and Wildlife Service (USFWS) to ensure that any action authorized, funded, or carried out by the Federal agency is not likely to jeopardize the continued existence of any endangered species or threatened species or result in the destruction or adverse modification of any critical habitat. The EPA incorporated a Biological Assessment (BA) into the EA to assess the potential effects of expanding the Charleston ODMDS on aquatic and wildlife species and submitted that document to the NMFS and USFWS on December 4, 2016. The EPA concluded that the proposed project would not adversely affect any threatened or endangered species, nor would it adversely modify any designated critical habitat. The USFWS concurred on the EPA's finding that the proposed action is not likely to adversely affect listed endangered or threatened species under the jurisdiction of the USFWS. The NMFS concluded the proposed action is not likely to adversely affect listed species under their jurisdiction.
The USACE and the EPA initiated consultation with the State of South Carolina's Historic Preservation Officer (SHPO) on December 4, 2015, to address the National Historic Preservation Act, as amended (NHPA), 16 U.S.C. 470 to 470a-2, which requires Federal agencies
This rule modifies the designation of an ODMDS pursuant to Section 102 of the MPRSA. This action complies with applicable executive orders and statutory provisions as follows:
This action is not a “significant regulatory action” under the terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is therefore not subject to review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011).
This action does not impose an information collection burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501
The Regulatory Flexibility Act (RFA) generally requires Federal agencies to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of this rule on small entities, small entity is defined as: (1) a small business defined by the Small Business Administration's size regulations at 13 CFR 121.201; (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. The EPA determined that this action will not have a significant economic impact on small entities because this rule will only have the effect of regulating the location of site to be used for the disposal of dredged material in ocean waters. After considering the economic impacts of this rule, I certify that this action will not have a significant economic impact on a substantial number of small entities.
This action contains no Federal mandates under the provisions of Title II of the Unfunded Mandates Reform Act (UMRA) of 1995, 2 U.S.C. 1531 to 1538, for State, local, or tribal governments or the private sector. This action imposes no new enforceable duty on any State, local or tribal governments or the private sector. Therefore, this action is not subject to the requirements of sections 202 or 205 of the UMRA. This action is also not subject to the requirements of section 203 of the UMRA because it contains no regulatory requirements that might significantly or uniquely affect small government entities. Those entities are already subject to existing permitting requirements for the disposal of dredged material in ocean waters.
This action does not have federalism implications. It 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 various levels of government, as specified in Executive Order 13132. Thus, Executive Order 13132 does not apply to this action. In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between the EPA and State and local governments, the EPA specifically solicited comments on this action from State and local officials.
This action does not have tribal implications, as specified in Executive Order 13175 because the modification of the Charleston ODMDS will not have a direct effect on Indian Tribes, on the relationship between the federal government and Indian Tribes, or on the distribution of power and responsibilities between the federal government and Indian Tribes. Thus, Executive Order 13175 does not apply to this action. The EPA specifically solicited comments from tribal officials.
The EPA interprets Executive Order 13045 as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under Section 5-501 of the Executive Order has the potential to influence the regulation. This action is not subject to Executive Order 13045 because it does not establish an environmental standard intended to mitigate health or safety risks. The action concerns the modification of the Charleston ODMDS and only has the effect of providing a designated location for ocean disposal of dredged material pursuant to Section 102 (c) of the MPRSA.
This action is not subject to Executive Order 13211, “Actions Concerning Regulations that Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355) because it is not a “significant regulatory action” as defined under Executive Order 12866.
Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (“NTTAA”), Public Law 104-113, 12(d) (15 U.S.C. 272), directs the EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (
Executive Order 12898 (59 FR 7629) 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 United States. The EPA determined that this rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because it does not affect the level of protection provided to human health or the environment. The EPA has assessed the overall protectiveness of modifying the Charleston ODMDS against the criteria established pursuant to the MPRSA to ensure that any adverse impact to the environment will be mitigated to the greatest extent practicable. We welcome comments on this action related to this Executive Order.
Environmental protection, Water pollution control.
This action is issued under the authority of Section 102 of the Marine Protection, Research, and Sanctuaries Act, as amended, 33 U.S.C. 1401, 1411, 1412.
For the reasons set out in the preamble, the EPA amends chapter I, title 40 of the Code of Federal Regulations as follows:
33 U.S.C. 1412 and 1418.
(h) * * *
(5) * * *
(i)
(ii)
(iii)
(vi)
(B) Disposal shall be limited to dredged material determined to be suitable for ocean disposal according to 40 CFR 227.13;
(C) Disposal shall be managed by the restrictions and requirements contained in the currently-approved Site Management and Monitoring Plan (SMMP);
(D) Monitoring, as specified in the SMMP, is required.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Final rule.
This final rule removes the medium and large vessel bottomfish prohibited fishing areas in the Commonwealth of the Northern Mariana Islands (CNMI). Conditions in the fishery that led to establishing the prohibited areas are no longer present, and the restriction is no longer necessary. This rule also makes administrative housekeeping changes to the description of the CNMI management subarea and to the regulations for the CNMI management subarea crustacean fishing. The intent of this final rule is to improve the viability of the CNMI bottomfish fishery and promote optimum yield while preventing overfishing.
Effective October 7, 2016.
The Western Pacific Fishery Management Council (Council) and NMFS prepared Amendment 4 to the Fishery Ecosystem Plan for the Marianas Archipelago that provides background information on this final rule. Amendment 4, including a final environmental assessment and regulatory impact review, is identified as NOAA-NMFS-2015-0115 and is available from
Sarah Ellgen, NMFS PIRO Sustainable Fisheries, 808-725-5173.
Federal regulations currently prohibit medium and large vessels (40 ft and greater) from commercial fishing for bottomfish management unit species in certain Federal waters around the CNMI. The prohibited areas include waters within approximately 50 nm of the Southern Islands (
The CNMI bottomfish fishery has changed since 2008, and the conditions that led the Council and NMFS to establish the prohibited areas are no longer present. Large vessels from Guam have not shown interest in fishing for CNMI bottomfish. The prohibited areas may also be negatively affecting the CNMI bottomfish fishery. Only a few small vessels have been operating on a regular basis, and the few medium and large vessels have faced declining participation, possibly resulting from higher fuel costs that prevent them from traveling beyond the prohibited areas. The prohibited areas may be contributing to the potential under-utilization of the bottomfish resource in CNMI, and removing them may promote optimum yield.
To address fishery conditions resulting from the CNMI prohibited areas, the Council recommended that NMFS remove them. The Council and NMFS will continue to manage the fishery under a suite of management
The Council and NMFS intend this final rule to improve the efficiency and economic viability of the CNMI bottomfish fishery. The Council and NMFS will annually review the effects of the action. Any future changes would be subject to additional environmental review and opportunity for public review and comment.
In addition to removing the prohibited areas, this final rule includes administrative housekeeping corrections to the description of the CNMI management subarea and to the CNMI permit area designation for crustacean fishing. First, prior to 2013, the CNMI management subarea was divided into an inshore area (the Exclusive Economic Zone, EEZ, within 3 nm of the shoreline) and an offshore area (the EEZ seaward of 3 nm from the shoreline). In 2013, under Public Law 113-34 (which amended Public Law 94-435) the United States transferred nearshore waters (0-3 nm) to the CNMI, so this distinction is no longer necessary. Second, the current regulations at § 665.442(a)(1) incorrectly refer to Permit Area 3, which is associated with American Samoa. The correct reference for the CNMI is Crustacean Permit Area 5, and this rule corrects that reference.
On June 13, 2016, NMFS published a proposed rule and request for public comments (81 FR 38123). The comment period ended on July 28, 2016. NMFS did not receive any comments.
There are no changes from the proposed rule.
The Regional Administrator, Pacific Islands Region, NMFS, determined that Amendment 4 is necessary for the conservation and management of the bottomfish fisheries of the Marianas Archipelago, and that it is consistent with the Magnuson-Stevens Fishery Conservation and Management Act and other applicable laws.
The Chief Counsel for Regulation of the Department of Commerce certified to the Chief Counsel for Advocacy of the Small Business Administration during the proposed rule stage that this action would not have a significant economic impact on a substantial number of small entities. NMFS published the factual basis for the certification in the proposed rule (81 FR 38123, June 13, 2016), and does not repeat it here. NMFS received no comments on this certification. However, NMFS has updated its analysis under a new small business size standard of $11 million in annual gross receipts for all businesses primarily engaged in the commercial fishing industry (NAICS 11411). This new size standard was established after the proposed rule was published.
On December 29, 2015, NMFS issued a final rule establishing the $11 million standard. This standard is for Regulatory Flexibility Act (RFA) compliance purposes only (80 FR 81194) and became effective on July 1, 2016, to be used in place of the U.S. Small Business Administration (SBA) current standards of $20.5 million, $5.5 million, and $7.5 million for the finfish (NAICS 114111), shellfish (NAICS 114112), and other marine fishing (NAICS 114119) sectors of the U.S. commercial fishing industry in all NMFS rules that are subject to the RFA after July 1, 2016.
Pursuant to the Regulatory Flexibility Act, and prior to July 1, 2016, a certification was developed for this regulatory action using the former SBA size standards. NMFS has reviewed the analyses prepared for this regulatory action in light of the new size standard. All of the entities directly regulated by this regulatory action are finfish commercial fishing businesses and were considered small under the SBA size standards, and they all would continue to be considered small under the new standard. Thus, NMFS has determined that the new size standard does not affect analyses prepared for this regulatory action and the factual basis for the certification submitted during the proposed rule stage stands. As a result, a regulatory flexibility analysis is not required, and none was prepared
This final rule has been determined to be not significant for purposes of Executive Order 12866.
Administrative practice and procedure, Commonwealth of the Northern Mariana Islands, Mariana Archipelago fisheries, Fisheries, Fishing, Guam, Permits, Reporting and recordkeeping requirements.
For the reasons set out in the preamble, NMFS amends 50 CFR part 665 as follows:
16 U.S.C. 1801
(b)
(c) The outer boundary of each fishery management area is a line drawn in such a manner that each point on it is 200 nautical miles from the baseline from which the territorial sea is measured, or is coterminous with adjacent international maritime boundaries. The boundary between the fishery management areas of Guam and the CNMI extends to those points that are equidistant between Guam and the island of Rota in the CNMI. CNMI and Guam management subareas are divided by a line intersecting these two points: 148° E. long., 12° N. lat., and 142° E. long., 16° N. lat.
The revisions read as follows:
(e) Use a vessel to fish commercially for Mariana bottomfish MUS in the CNMI management subarea without a valid CNMI commercial bottomfish permit registered for use with that vessel, in violation of § 665.404(a)(2).
(f) Falsify or fail to make, keep, maintain, or submit a Federal logbook as required under § 665.14(b) when using a vessel to engage in commercial fishing for Mariana bottomfish MUS in the CNMI management subarea in violation of § 665.14(b).
(a) * * *
(1) The owner of any vessel used to fish for lobster in Crustacean Permit Area 5 must have a permit issued for such a vessel.
Council of the Inspectors General on Integrity and Efficiency.
Proposed rule.
The Council of the Inspectors General on Integrity and Efficiency (CIGIE) is issuing this proposed rule to establish its procedures relating to access, maintenance, disclosure, and amendment of records that are in a CIGIE system of records under the Privacy Act of 1974 (Privacy Act). The proposed rule also establishes rules of conduct for CIGIE personnel who have responsibilities under the Privacy Act.
Submit comments on or before November 7, 2016.
You may submit comments by any of the following methods:
•
•
•
•
•
Atticus J. Reaser, General Counsel, CIGIE, (202) 292-2600.
CIGIE is issuing this proposed rule to provide the procedures and guidelines under which CIGIE will implement the Privacy Act.
In 2008, Congress established CIGIE as an independent entity within the executive branch in order to address integrity, economy, and effectiveness issues that transcend individual Government agencies; and increase the professionalism and effectiveness of personnel by developing policies, standards, and approaches to aid in the establishment of a well-trained and highly skilled workforce in the offices of the Inspectors General (OIG). CIGIE's membership is comprised of all Inspectors General whose offices are established under section 2 or section 8G of the Inspector General Act of 1978, Public Law 95-452, 92 Stat. 1101 (codified as amended at 5 U.S.C. app) (Inspector General Act) (
Section 11(d) of the Inspector General Act mandates that CIGIE have an Integrity Committee (IC), which shall receive, review, and refer for investigation allegations of wrongdoing that are made against Inspectors General and designated staff members of the various OIGs. Pursuant to section 11(d)(2)(A) of the Inspector General Act, all records received or created by the IC in fulfilling its responsibilities are collected and maintained separately as IC records by the official of the FBI serving on the IC. As of the issuance of this proposed rule, all such records are maintained in FBI's Central Records System and are subject to the system of records notices and the Privacy Act policies and regulations applicable to that system. See 28 CFR part 16, subpart D. Accordingly, unless otherwise specifically stated, the regulations published below do not apply to records maintained by the IC.
In promulgating this rule, CIGIE has adhered to the regulatory philosophy and the applicable principles of regulation set forth in section 1 of Executive Order 12866, Regulatory Planning and Review. The Office of Management and Budget has determined that this rule is not “significant” under Executive Order 12866.
These proposed regulations will not have a significant economic impact on a substantial number of small entities. Therefore, a regulatory flexibility analysis as provided by the Regulatory Flexibility Act, as amended, is not required.
These proposed regulations impose no additional reporting and recordkeeping requirements. Therefore, clearance by OMB is not required.
This rule does not have Federalism implications, as set forth in Executive Order 13132. 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.
Information, Privacy, Privacy Act, Records.
Section 11 of the Inspector General Act of 1978, Pub. L. 95-452, 92 Stat. 1101 (codified as amended at 5 U.S.C. app); 5 U.S.C. 301, 552a; 31 U.S.C. 9701.
This part contains the regulations of the Council of the Inspectors General on Integrity and Efficiency (CIGIE) implementing the Privacy Act of 1974, 5 U.S.C. 552a. This part sets forth the basic responsibilities of CIGIE with regard to CIGIE's compliance with the requirements of the Privacy Act and offers guidance to members of the public who wish to exercise any of the rights established by the Privacy Act with regard to records maintained by CIGIE. These regulations should be read in conjunction with the Privacy Act, which explains in more detail individuals' rights.
(a)
(b)
(c)
(a) For purposes of this part the terms
(b)
(c)
(d)
(e)
(f)
(g)
(h)
An individual seeking to determine if a specific CIGIE system of records contains a record pertaining to the individual must follow the procedures set forth for access to records in § 9801.201(a), (b)(1) and (2), (c), and (d). A request to determine if an individual is the subject of a record will ordinarily be responded to within 10 days, except when CIGIE determines otherwise, in which case the request will be acknowledged within 10 days and the individual will be informed of the reasons for the delay and an estimated date by which a response will be issued.
CIGIE will inform its employees involved in the design, development, operation, or maintenance of any system of records, or in maintaining any record, of the provisions of the Privacy Act, including the Act's civil liability and criminal penalty provisions. Unless otherwise permitted by law, an employee of CIGIE shall:
(a) Collect from individuals only the information that is relevant and necessary to discharge the responsibilities of CIGIE;
(b) Collect information about an individual directly from that individual whenever practicable when the information may result in adverse determinations about an individual's rights, benefits, and privileges under Federal programs;
(c) Inform each individual from whom information is collected of:
(1) The legal authority to collect the information and whether providing it is mandatory or voluntary;
(2) The principal purpose for which CIGIE intends to use the information;
(3) The routine uses CIGIE may make of the information; and
(4) The effects on the individual, if any, of not providing the information;
(d) Maintain no system of record without public notice and notify appropriate CIGIE officials of the existence or development of any system of records that is not the subject of a current or planned public notice;
(e) Maintain all records that are used by CIGIE in making any determination about an individual with such accuracy, relevance, timeliness, and completeness as is reasonably necessary to ensure fairness to the individual in the determination;
(f) Except as to disclosures made to an agency or made under the Freedom of Information Act, 5 U.S.C. 552 (FOIA), make reasonable efforts, prior to disseminating any record about an individual, to ensure that the record is accurate, relevant, timely, and complete;
(g) Maintain no record describing how an individual exercises his or her First Amendment rights, unless it is expressly authorized by statute or by the individual about whom the record is maintained, or is pertinent to and within the scope of an authorized law enforcement activity;
(h) When required by the Privacy Act, maintain an accounting in the specified form of all disclosures of records by
(i) Maintain and use records with care to prevent the unauthorized or inadvertent disclosure of a record to anyone. No record contained in a CIGIE system of record shall be disclosed to another person, or to another agency outside CIGIE, except pursuant to a written request by, or with the prior written consent of, the individual to whom the record pertains, unless the disclosure is otherwise authorized by the Privacy Act; and
(j) Notify the appropriate CIGIE official of any record that contains information that the Privacy Act does not permit CIGIE to maintain.
(a)
(b)
(1) Whether providing social security numbers is mandatory or voluntary;
(2) The statutory or regulatory authority that authorizes the collection of social security numbers; and
(3) The uses that will be made of the numbers.
Nothing in this part shall be construed to entitle any person, as of right, to any service or to the disclosure of any record to which such person is not entitled under the Privacy Act.
(a)
(b)
(2) If the written inquiry does not refer to a specific system of records, it must describe the records that are sought in enough detail to enable CIGIE personnel to locate the system of records containing them with a reasonable amount of effort.
(3) The request should state whether the requester wants a copy of the record or wants to examine the record in person.
(c)
(d)
(1) The identity of the individual who is the subject of the record, by stating the name, current address, date and place of birth, and, at the requester's option, the social security number of the individual;
(2) The requester's identity, as required in paragraph (c) of this section;
(3) That the requester is the parent or guardian of that individual, which may be established by providing a copy of the individual's birth certificate showing the requester's parentage or by providing a court order establishing the requester's guardianship; and
(4) That the requester is acting on behalf of that individual in making the request.
A request for access will ordinarily be responded to within 10 days, except when CIGIE determines otherwise, in which case the request will be acknowledged within 10 days and the requester will be informed of the reasons for the delay and an estimated date by which a response will be issued. A response to a request for access should include the following:
(a) A statement that there is a record or records as requested or a statement that there is not a record in the system of records;
(b) The method of access (if a copy of all the records requested is not provided with the response);
(c) The amount of any fees to be charged for copies of records under § 9801.207, if applicable;
(d) The name and title of the official responsible for the response; and
(e) If the request is denied in whole or in part, or no record is found in the system, a statement of the reasons for the denial, or a statement that no record has been found, and notice of the procedures for appealing the denial or no record finding.
(a)
(i) Examination in person in a designated office during the hours specified by CIGIE; or
(ii) Providing copies of the records.
(2) When a requester has not indicated whether he wants a copy of the record or wants to examine the record in person, CIGIE may choose the means of granting access. However, the means chosen should not unduly impede the requester's right of access. A requester may elect to receive a copy of the records after having examined them.
(b)
(c)
(d)
In the event CIGIE receives a request pursuant to § 9801.201 for access to medical records (including psychological records) whose disclosure CIGIE determines would be harmful to the individual to whom they relate, it may refuse to disclose the records directly to the requester but shall transmit them to a physician designated by the requester.
(a)
(b)
(a)
(b)
(c)
(a)
(1) The search and review time expended by CIGIE to produce a record;
(2) The first copy of the records provided; and
(3) CIGIE making the records available to be personally reviewed by the requester.
(b)
(1) If the total fee for additional copies amounts to more than $25.00, the requester will be notified of the fee amount. Except as specified in paragraph (b)(2) of this section, upon requester's written agreement to pay the assessed fees, CIGIE will provide the additional copies without prepayment of such fees (
(2) An advance payment before additional copies of the records are made will be required if:
(i) CIGIE determines that the total fee to be assessed under this section exceeds $250.00. When such a determination is made, the requester will be notified of the determination and will be required to submit an advance payment of an amount up to the total fee. The amount of the advanced payment will be at the sole discretion of CIGIE and will be based, in part, on whether requester has a history of prompt payment of Privacy Act fees. If the required advanced payment is an amount less than the total fee, requester will be required to submit a written agreement to pay any fees not paid in advance; or
(ii) The requester has previously failed to pay a previously assessed Privacy Act fee in a timely fashion (
(c)
(d)
(a)
(b)
(1) Disclosures for which accountings are not required to be kept, including disclosures that are made to officers and employees of CIGIE and disclosures that are made under the FOIA. For purposes of this part, officers and employees of CIGIE includes, in part, CIGIE's membership, as addressed in section 11 of the Inspector General Act, when such members are acting in their capacity as CIGIE members;
(2) Disclosures made to law enforcement agencies for authorized law enforcement activities in response to written requests from those law enforcement agencies specifying the law enforcement activities for which the disclosures are sought; or
(3) Disclosures made from law enforcement systems of records that have been exempted from accounting requirements.
(a)
(b)
(1) The name of the system of records and a brief description of the record proposed for amendment. In the event the request to amend the record is the result of the requester having gained access to the record in accordance with the provisions concerning access to records as set forth in subpart B of this part, copies of previous correspondence between the requester and CIGIE will serve in lieu of a separate description of the record.
(2) The exact portion of the record the requester seeks to have amended should be indicated clearly. If possible, proposed alternative language should be set forth, or, at a minimum, the reasons why the requester believes the record is not accurate, relevant, timely, or complete should be set forth with enough particularity to permit CIGIE to not only to understand the requester's basis for the request, but also to make an appropriate amendment to the record.
(c)
(d)
(a)
(b)
(1) If CIGIE grants the request, the appropriate system manager will amend the record(s) and provide a copy of the amended record(s) to the requester. To the extent an accounting of disclosure has been maintained, the system manager shall advise all previous recipients of the record that an amendment has been made and give the substance of the amendment. Where practicable, the system manager shall send a copy of the amended record to previous recipients.
(2) If CIGIE denies the request in whole or in part, the reasons for the denial will be stated in the response letter. In addition, the response letter will state:
(i) The name and address of the official with whom an appeal of the denial may be lodged; and
(ii) A description of any other procedures which may be required of the requester in order to process the appeal.
(a)
(b)
(a)
(b)
(1) To amend the record(s); and
(2) To notify previous recipients of the record(s) for which there is an accounting of disclosure that the record(s) have been amended.
(c)
(1) Obtain judicial review of the decision in accordance with the terms of the Privacy Act at 5 U.S.C. 552a(g); and
(2) File a statement setting forth their reasons for disagreeing with the decision.
(d)
(e)
Requesters may seek assistance in preparing a request to amend a record or an appeal of an initial adverse determination, or to learn further of the provisions for judicial review, by contacting CIGIE's Privacy Officer by email at
Federal Trade Commission.
Request for public comment.
The Federal Trade Commission (“FTC” or “Commission”) requests public comment on its Standards for Safeguarding Customer Information (“Safeguards Rule” or “Rule”). The Commission is soliciting comment as part of the FTC's systematic review of all current Commission regulations and guides.
Comments must be received on or before November 7, 2016.
Interested parties may file a comment online or on paper by following the Instructions for Submitting Comments part of the
David Lincicum or Katherine McCarron, Division of Privacy and Identity Protection, Bureau of Consumer Protection, Federal Trade Commission, 600 Pennsylvania Avenue NW., Washington, DC 20580, (202) 326-2773 or (202) 326-2333.
The Gramm-Leach-Bliley Act (“G-L-B Act” or “Act”) was enacted in 1999 to reform and modernize the banking industry by eliminating existing barriers between banking and commerce. The Act permits banks to engage in a broad range of activities, including insurance and securities brokering, with new affiliated entities. Subtitle A of Title V of the Act, captioned “Disclosure of Nonpublic Personal Information,” limits the instances in which a financial institution may disclose nonpublic personal information about a consumer to nonaffiliated third parties, and requires a financial institution to disclose certain information sharing practices. In 2000, the Commission issued a final rule that implemented Subtitle A as it relates to these requirements (hereinafter “Privacy Rule”).
Subtitle A of Title V also required the Commission and other federal agencies to establish standards for financial institutions relating to administrative, technical, and physical safeguards for certain information.
Pursuant to the Act's directive, the Commission promulgated the Safeguards Rule in 2002. The Safeguards Rule applies to all “financial institutions” over which the Commission has jurisdiction. The Safeguards Rule uses the definition of “financial institution” from the Privacy Rule.
When promulgating the Privacy Rule, the Commission determined to include as “financial activities” only those activities that the Fed found to be “financial in nature,” and not to include those activities that the Fed found to be “incidental” or “complementary” to financial activities.
The Safeguards Rule applies to the handling of “customer information” by financial institutions. “Customer information” is defined as “any record containing nonpublic personal information . . . about a customer of a financial institution, whether in paper, electronic, or other form” that is “handled or maintained by or on behalf of” a financial institution or its affiliates.
The Safeguards Rule requires financial institutions to develop, implement, and maintain a comprehensive information security program.
In order to develop, implement, and maintain its information security program, a financial institution must identify reasonably foreseeable internal and external risks to the security, confidentiality, and integrity of customer information that could result in the unauthorized disclosure, misuse, alteration, destruction, or other compromise of such information, including in the areas of: (1) Employee training and management; (2) information systems, including network and software design, as well as information processing, storage, transmission, and disposal; and (3) detecting, preventing, and responding to attacks, intrusions, or other systems failures.
The Safeguards Rule also requires financial institutions to take reasonable steps to select and retain service providers that are capable of maintaining appropriate safeguards for customer information and require those service providers by contract to implement and maintain such safeguards.
The Safeguards Rule became effective on May 23, 2003.
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 solicits comments on, among other things, the economic impact and benefits of the Rule; possible conflict between the Rule and state, local, or other federal laws or regulations; and the effect on the Rule of any technological, economic, or other industry changes.
The Commission requests written comment on any or all of the following questions. These questions are designed to assist the public and should not be construed as a limitation on the issues about which public comment may be submitted. The Commission requests that responses to its questions be as specific as possible, including a reference to the question being answered, and refer to empirical data or other evidence upon which the comment is based whenever available and appropriate. Please also provide evidence of the prevalence of any unfair acts or practices that any proposed modification would address.
1. Is there a continuing need for specific provisions of the Rule? Why or why not?
2. What benefits has the Rule provided to consumers? What evidence supports the asserted benefits?
3. What modifications, if any, should be made to the Rule to increase its benefits to consumers?
a. What evidence supports the proposed modifications?
b. How would these modifications affect the costs the Rule imposes on businesses, including small businesses?
4. What significant costs, if any, has the Rule imposed on consumers? What evidence supports the asserted costs?
5. What modifications, if any, should be made to the Rule to reduce any costs imposed on consumers?
a. What evidence supports the proposed modifications?
b. How would these modifications affect the benefits provided by the Rule?
6. What benefits, if any, has the Rule provided to businesses, including small businesses? What evidence supports the asserted benefits?
7. What modifications, if any, should be made to the Rule to increase its benefits to businesses, including small businesses?
a. What evidence supports the proposed modifications?
b. How would these modifications affect the costs the Rule imposes on businesses, including small businesses?
c. How would these modifications affect the benefits to consumers?
8. What significant costs, if any, including costs of compliance, has the Rule imposed on businesses, including small businesses? What evidence supports the asserted costs?
9. What modifications, if any, should be made to the Rule to reduce the costs imposed on businesses, including small businesses?
a. What evidence supports the proposed modifications?
b. How would these modifications affect the benefits provided by the Rule?
10. What evidence is available concerning the degree of industry compliance with the Rule?
11. What modifications, if any, should be made to the Rule to account for changes in relevant technology or economic conditions? What evidence supports the proposed modifications?
12. Does the 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 Rule be modified? If so, why, and how? If not, why not?
1. Should the elements of an information security program include a response plan in the event of a breach that affects the security, integrity, or confidentiality of customer information? Why or why not? If so, what should such a plan contain?
a. What evidence supports such a modification?
b. How would this modification affect the costs the Rule imposes on businesses, including small businesses?
c. How would this modification affect the benefits to businesses?
d. How would this modification affect the costs the Rule imposes on consumers?
e. How would this modification affect the benefits to consumers?
2. Should the Rule be modified to include more specific and prescriptive requirements for information security plans? Why or why not? If so, what requirements should be included and what sources should they be drawn from?
a. What evidence supports such a modification?
b. How would this modification affect the costs the Rule imposes on businesses, including small businesses?
c. How would this modification affect the benefits to businesses?
d. How would this modification affect the costs the Rule imposes on consumers?
e. How would this modification affect the benefits to consumers?
3. Should the Rule be modified to reference or incorporate any other information security standards or frameworks, such as the National Institute of Standards and Technology's Cybersecurity Framework or the Payment Card Industry Data Security Standards? If so, which standards should be incorporated or referenced and how should they by referenced or incorporated by the Rule?
a. What evidence supports such a modification?
b. How would this modification affect the costs the Rule imposes on businesses, including small businesses?
c. How would this modification affect the benefits to businesses?
d. How would this modification affect the costs the Rule imposes on consumers?
e. How would this modification affect the benefits to consumers?
4. For the purpose of clarity, should the Rule be modified to include its own definitions of terms, such as “financial institution”, rather than incorporating the definitions found in the Privacy Rule?
a. What evidence supports such a modification?
b. How would this modification affect the costs the Rule imposes on businesses, including small businesses?
c. How would this modification affect the benefits to businesses?
d. How would this modification affect the costs the Rule imposes on consumers?
e. How would this modification affect the benefits to consumers?
5. The current Safeguards Rule incorporates the Privacy Rule's definition of “financial institutions” as entities that are significantly engaged in financial activities, including activities found to be closely related to banking by regulation or order in effect at the time of enactment of the G-L-B Act. Should the Safeguards Rule's definition of “financial institution” be modified to also include entities that are significantly engaged in activities that the Federal Reserve Board has found to be incidental to financial activities? Should it also include activities that have been found to be closely related to banking or incidental to financial activities by regulation or order in effect
a. How would this modification affect the costs the Rule imposes on businesses, including small businesses?
b. How would this modification affect the benefits to businesses?
c. How would this modification affect the costs the Rule imposes on consumers?
d. How would this modification affect the benefits to consumers?
You can file a comment online or on paper. For the Commission to consider your comment, we must receive it on or before November 7, 2016. Write “Safeguards Rule, 16 CFR 314, Matter No. P145407” on the 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
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 General Counsel grants your request in accordance with the law and the public interest.
Postal mail addressed to the Commission is subject to delay due to heightened security screening. As a result, we encourage you to submit your comment online. To make sure that the Commission considers your online comment, you must file it at
If you file your comment on paper, write “Safeguards Rule, 16 CFR 314, Matter No. P145407” 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 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.
Visit the Commission Web site at
By direction of the Commission.
Drug Enforcement Administration, Department of Justice.
Notice of intent.
The Administrator of the Drug Enforcement Administration is issuing this notice of intent to temporarily schedule the synthetic opioid, 3,4-dichloro-
September 7, 2016.
Michael J. Lewis, Office of Diversion Control, Drug Enforcement Administration; Mailing Address: 8701 Morrissette Drive, Springfield, Virginia 22152; Telephone: (202) 598-6812.
Any final order will be published in the
The Drug Enforcement Administration (DEA) implements and enforces titles II and III of the Comprehensive Drug Abuse Prevention and Control Act of 1970, as amended. 21 U.S.C. 801-971. Titles II and III are referred to as the “Controlled Substances Act” and the “Controlled Substances Import and Export Act,” respectively, and are collectively referred to as the “Controlled Substances Act” or the “CSA” for the purpose of this action. The DEA publishes the implementing regulations for these statutes in title 21 of the Code of Federal Regulations (CFR), chapter II. The CSA and its implementing regulations are designed to prevent, detect, and eliminate the diversion of controlled substances and listed chemicals into the illicit market while providing for the legitimate medical, scientific, research, and industrial needs of the United States. Controlled substances have the potential for abuse and dependence and are controlled to protect the public health and safety.
Under the CSA, each controlled substance is classified into one of five schedules based upon its potential for abuse, its currently accepted medical use in treatment in the United States, and the degree of dependence the drug or other substance may cause. 21 U.S.C. 812. The initial schedules of controlled substances established by Congress are found at 21 U.S.C. 812(c), and the current list of all scheduled substances is published at 21 CFR part 1308.
Section 201 of the CSA, 21 U.S.C. 811, provides the Attorney General with the authority to temporarily place a substance into schedule I of the CSA for two years without regard to the requirements of 21 U.S.C. 811(b) if she finds that such action is necessary to avoid imminent hazard to the public safety. 21 U.S.C. 811(h)(1). In addition, if proceedings to control a substance are initiated under 21 U.S.C. 811(a)(1), the Attorney General may extend the temporary scheduling for up to one year. 21 U.S.C. 811(h)(2).
Where the necessary findings are made, a substance may be temporarily scheduled if it is not listed in any other schedule under section 202 of the CSA, 21 U.S.C. 812, or if there is no exemption or approval in effect for the substance under section 505 of the Federal Food, Drug, and Cosmetic Act (FDCA), 21 U.S.C. 355. 21 U.S.C. 811(h)(1). The Attorney General has delegated scheduling authority under 21 U.S.C. 811 to the Administrator of the DEA. 28 CFR 0.100.
Section 201(h)(4) of the CSA, 21 U.S.C. 811(h)(4), requires the Administrator to notify the Secretary of the Department of Health and Human Services (HHS) of his intention to temporarily place a substance into schedule I of the CSA.
To find that placing a substance temporarily into schedule I of the CSA is necessary to avoid an imminent hazard to the public safety, the Administrator is required to consider three of the eight factors set forth in section 201(c) of the CSA, 21 U.S.C. 811(c): The substance's history and current pattern of abuse; the scope, duration and significance of abuse; and what, if any, risk there is to the public health. 21 U.S.C. 811(h)(3). Consideration of these factors includes actual abuse, diversion from legitimate channels, and clandestine importation, manufacture, or distribution. 21 U.S.C. 811(h)(3).
A substance meeting the statutory requirements for temporary scheduling may only be placed in schedule I. 21 U.S.C. 811(h)(1). Substances in schedule I are those that have a high potential for abuse, no currently accepted medical use in treatment in the United States, and a lack of accepted safety for use under medical supervision. 21 U.S.C. 812(b)(1).
The substance U-47700 was first described in 1978 in the patent literature. Publications in the scientific literature in the early 1980's found that U-47700 behaved similarly to morphine in animal models. No approved medical
Available data and information for U-47700, summarized below, indicate that this synthetic opioid has a high potential for abuse, no currently accepted medical use in treatment in the United States, and a lack of accepted safety for use under medical supervision. The DEA's three-factor analysis is available in its entirety under the public docket of this action as a supporting document at
The National Forensic Laboratory Information System (NFLIS) is a national drug forensic laboratory reporting system that systematically collects results from drug chemistry analyses conducted by State and local forensic laboratories across the country. The first laboratory submissions of U-47700 were recorded in the first quarter of 2016; 10 records were reported from January-March 2016 according to NFLIS (query date: 06/20/2016).
On October 1, 2014, the DEA implemented STARLiMS (a web-based, commercial laboratory information management system) as its laboratory drug evidence data system of record. DEA laboratory data submitted after September 30, 2014, are reposited in STARLiMS; data from STARLiMS were queried on April 12, 2016. STARLiMS registered one report containing U-47700 in 2016 from Montana. Through information collected from law enforcement reports and personal communications,
Evidence suggests that the pattern of abuse of synthetic opioids, including U-47700, parallels that of heroin and prescription opioid analgesics. Seizures of U-47700 have been encountered in powder form and in counterfeit tablets that mimic pharmaceutical opioids. U-47700 has also been encountered in glassine bags and envelopes and knotted corners of plastic bags, which demonstrates the abuse of this substance as a replacement for heroin or other opioids, either knowingly or unknowingly. U-47700 has been encountered as a single substance as well as in combination with other substances, including heroin, fentanyl, and furanyl fentanyl.
The DEA is currently aware of at least 15 confirmed fatalities associated with U-47700. The information on these deaths occurring in 2015 and 2016 was collected from personal communications and toxicology and medical examiner reports and was reported from New Hampshire (1), North Carolina (10), Ohio (1), Texas (2), and Wisconsin (1). The population likely to abuse U-47700 appears to overlap with the populations abusing prescription opioid analgesics and heroin, as evidenced by drug use history documented in U-47700 fatal overdose cases. This is further supported by U-47700 being sold on the illicit market in glassine bags, some of which are marked with stamped logos, imitating the sale of heroin. Because abusers of U-47700 are likely to obtain this substance through non-regulated sources, the identity, purity, and quantity is uncertain and inconsistent, thus posing significant adverse health risks to the end user. Individuals who initiate (
STARLiMS contains a report in which U-47700 was identified in drug exhibits submitted in 2016 from Montana. A query of NFLIS returned 10 records of U-47700 being identified in exhibits submitted to Federal, State and local forensic laboratories in the first quarter of 2016. The DEA is not aware of any laboratory analyses of drug evidence identifying U-47700 prior to 2015, indicating that this synthetic opioid only recently became available as a replacement for other opioids that are commonly abused (
U-47700 exhibits pharmacological profiles similar to that of morphine and other mu-opioid receptor agonists. Due to limited scientific data, the potency and toxicity of U-47700 are not known; however, the toxic effects of U-47700 in humans are demonstrated by overdose fatalities associated with this substance. Abusers of U-47700 may not know the origin, identity, or purity of these substances, thus posing significant adverse health risks when compared to abuse of pharmaceutical preparations of opioid analgesics, such as morphine and oxycodone.
Based on the documented case reports of overdose fatalities, the abuse of U-47700 leads to the same qualitative public health risks as heroin, fentanyl and other opioid analgesic substances. The public health risks attendant to the abuse of heroin and opioid analgesics are well established and have resulted in large numbers of drug treatment admissions, emergency department visits, and fatal overdoses.
U-47700 has been associated with fatalities. At least 15 confirmed overdose deaths involving U-47700 occurred in 2015 and 2016 in New Hampshire (1), North Carolina (10), Ohio (1), Texas (2), and Wisconsin (1). This indicates that U-47700 poses an imminent hazard to the public safety.
In accordance with 21 U.S.C. 811(h)(3), based on the available data and information summarized above, the continued uncontrolled manufacture, distribution, reverse distribution, importation, exportation, conduct of research and chemical analysis, possession, and abuse of U-47700 poses an imminent hazard to the public safety. The DEA is not aware of any currently accepted medical uses for U-47700 in the United States. A substance meeting the statutory requirements for temporary scheduling, 21 U.S.C. 811(h)(1), may only be placed in schedule I. Substances in schedule I are those that have a high potential for abuse, no currently accepted medical use in treatment in the United States, and a lack of accepted safety for use under medical supervision. Available data and
This notice of intent initiates an expedited temporary scheduling action and provides the 30-day notice pursuant to section 201(h) of the CSA, 21 U.S.C. 811(h). In accordance with the provisions of section 201(h) of the CSA, 21 U.S.C. 811(h), the Administrator considered available data and information, herein set forth the grounds for his determination that it is necessary to temporarily schedule U-47700 in schedule I of the CSA, and finds that placement of this synthetic opioid into schedule I of the CSA is necessary in order to avoid an imminent hazard to the public safety.
Because the Administrator hereby finds that it is necessary to temporarily place this synthetic opioid into schedule I to avoid an imminent hazard to the public safety, any subsequent final order temporarily scheduling this substance will be effective on the date of publication in the
The CSA sets forth specific criteria for scheduling a drug or other substance. Regular scheduling actions in accordance with 21 U.S.C. 811(a) are subject to formal rulemaking procedures done “on the record after opportunity for a hearing” conducted pursuant to the provisions of 5 U.S.C. 556 and 557. 21 U.S.C. 811. The regular scheduling process of formal rulemaking affords interested parties with appropriate process and the government with any additional relevant information needed to make a determination. Final decisions that conclude the regular scheduling process of formal rulemaking are subject to judicial review. 21 U.S.C. 877. Temporary scheduling orders are not subject to judicial review. 21 U.S.C. 811(h)(6).
Section 201(h) of the CSA, 21 U.S.C. 811(h), provides for an expedited temporary scheduling action where such action is necessary to avoid an imminent hazard to the public safety. As provided in this subsection, the Attorney General may, by order, schedule a substance in schedule I on a temporary basis. Such an order may not be issued before the expiration of 30 days from (1) the publication of a notice in the
Inasmuch as section 201(h) of the CSA directs that temporary scheduling actions be issued by order and sets forth the procedures by which such orders are to be issued, the DEA believes that the notice and comment requirements of section 553 of the Administrative Procedure Act (APA), 5 U.S.C. 553, do not apply to this notice of intent. In the alternative, even assuming that this notice of intent might be subject to section 553 of the APA, the Administrator finds that there is good cause to forgo the notice and comment requirements of section 553, as any further delays in the process for issuance of temporary scheduling orders would be impracticable and contrary to the public interest in view of the manifest urgency to avoid an imminent hazard to the public safety.
Although the DEA believes this notice of intent to issue a temporary scheduling order is not subject to the notice and comment requirements of section 553 of the APA, the DEA notes that in accordance with 21 U.S.C. 811(h)(4), the Administrator will take into consideration any comments submitted by the Assistant Secretary with regard to the proposed temporary scheduling order.
Further, the DEA believes that this temporary scheduling action is not a “rule” as defined by 5 U.S.C. 601(2), and, accordingly, is not subject to the requirements of the Regulatory Flexibility Act (RFA). The requirements for the preparation of an initial regulatory flexibility analysis in 5 U.S.C. 603(a) are not applicable where, as here, the DEA is not required by section 553 of the APA or any other law to publish a general notice of proposed rulemaking.
Additionally, this action is not a significant regulatory action as defined by Executive Order 12866 (Regulatory Planning and Review), section 3(f), and, accordingly, this action has not been reviewed by the Office of Management and Budget (OMB).
This action 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. Therefore, in accordance with Executive Order 13132 (Federalism) it is determined that this action does not have sufficient federalism implications to warrant the preparation of a Federalism Assessment.
Administrative practice and procedure, Drug traffic control, Reporting and recordkeeping requirements.
For the reasons set out above, the DEA proposes to amend 21 CFR part 1308 as follows:
21 U.S.C. 811, 812, 871(b), unless otherwise noted.
The addition reads as follows:
(h) * * *
(21) 3,4-Dichloro-
Coast Guard, DHS.
Advance notice of proposed rulemaking; change in comment period.
The Coast Guard is changing the comment period on the advance notice of proposed rulemaking (ANPRM) it published June 9, 2016, regarding anchorage grounds on the Hudson River from Yonkers, NY, to Kingston, NY. Comments will now be due on or before December 6, 2016 instead of September 7, 2016. As of August 29, 2016, the Coast Guard has received more than 2,100 public submissions from many interested persons commenting on the ANPRM. We are extending the comment period to continue encouraging this important public discussion.
Comments and related material must be received by the Coast Guard on or before December 6, 2016.
You may submit comments identified by docket number USCG-2016-0132 using the Federal eRulemaking Portal at
If you have questions on this document, call or email Mr. Craig Lapiejko, Waterways Management Branch at Coast Guard First District, telephone 617-223-8351, email
We view public participation as essential to effective rulemaking, and will consider all comments and material received due on or before December 6, 2016. Your comments can help shape the outcome of this possible rulemaking. If you submit a comment, please include the docket number for this rulemaking, indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation.
We encourage you to submit comments through the Federal eRulemaking Portal at
We accept anonymous comments. All comments received will be posted without change to
Documents mentioned in the ANPRM as being available in the docket, and all public comments, will be in our online docket at
The Coast Guard is responsible for considering adjustments to improve navigational and environmental safety of waterways, including those requested by groups of mariners. On June 9, 2016, the Coast Guard published an ANPRM in the
Public participation is requested to assist in determining the best way forward with respect to establishing new anchorage grounds on the Hudson River between Yonkers, NY, to Kingston, NY. To aid us in developing a possible proposed rule, we seek any comments, whether positive or negative, including but not limited to the impacts anchorage grounds may have on navigation safety and current vessel traffic in this area, the proposed number and size of vessels anchoring in each proposed anchorage ground, and the authorized duration for each vessel in each proposed anchorage ground. We are also seeking comments on any additional locations where anchorage grounds may be helpful on the Hudson River or any recommended alterations to the specific locations considered in this notice. Please submit any comments or concerns you may have in accordance with the “Public Participation and Request for Comments” section above.
Office of Population Affairs, Office of the Secretary, Department of Health and Human Services.
Notice of proposed rulemaking.
This document seeks comment on the proposed amendment of Title X regulations specifying the requirements Title X projects must meet to be eligible for awards. The amendment precludes project recipients from using criteria in their selection of subrecipients that are unrelated to the ability to deliver services to program beneficiaries in an effective manner.
To be considered, comments should be submitted by October 7, 2016. Subject to consideration of the comments submitted, the Department will publish final regulations.
You may submit comments, identified by Regulatory Information Number (RIN) 937-AA04, by any of the following methods:
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Susan B. Moskosky, MS, WHNP-BC, Office of Population Affairs (OPA), 200 Independence Avenue SW., Suite 716G, Washington, DC 20201; telephone: 240-453-2800; facsimile: 240-453-2801; email:
The Title X Family Planning Program, Public Health Service Act (PHSA) secs. 1001
Title X serves women, men, and adolescents to enable individuals to freely determine the number and spacing of children. By law, services are provided to low-income individuals at no or reduced cost. Services provided through Title X-funded health centers assist in preventing unintended pregnancies and achieving pregnancies that result in positive birth outcomes. These services include contraceptive services, pregnancy testing and counseling, preconception health services, screening and treatment for sexually transmitted diseases (STD) and HIV testing and referral for treatment, services to aid with achieving pregnancy, basic infertility services, and screening for cervical and breast cancer. By statute, Title X funds are not available to programs where abortion is a method of family planning (PHSA sec. 1008), and no federal funds in Title X or any federal program may be expended for abortions except in cases of rape, incest, or where the life of the mother would be endangered.
The Title X statute authorizes the Secretary “to make grants to and enter into contracts with public or nonprofit private entities to assist in the establishment and operation of voluntary family planning projects which shall offer a broad range of acceptable and effective family planning methods and services (including natural family planning methods, infertility services, and services for adolescents).” PHSA sec. 1001(a). In addition, in awarding Title X grants and contracts, the Secretary must “take into account the number of patients to be served, the relative need of the applicant, and its capacity to make rapid and effective use of such assistance.” PHSA sec. 1001(b). The statute also mandates that local and regional entities “shall be assured the right to apply for direct grants and contracts.” PHSA sec. 1001(b). The statute delegates rulemaking authority to the Secretary to set the terms and conditions of these grants and contracts. PHSA sec. 1006. These regulations were last revised in 2000. 65 FR 41270 (July 3, 2000).
Title X regulations delineating the criteria used to decide which family planning projects to fund and in what amount, include, among other factors, the extent to which family planning services are needed locally, the number of patients to be served (and, in particular, low-income patients), and the adequacy of the applicant's facilities and staff. 42 CFR 59.7. Project recipients receive funds directly from the Federal government following a competitive process. The project recipients may elect to provide Title X services directly or by subawarding funds to qualified entities (subrecipients). HHS is responsible for monitoring and evaluating the project recipient's performance and outcomes, and each project recipient that subawards to qualified subrecipients is responsible for monitoring the performance and outcomes of those subrecipients. The subrecipients must meet the same Federal requirements as the project recipients, including being a public or private nonprofit entity, and adhering to all Title X and other applicable federal requirements. In the event of poor performance or noncompliance, a project recipient may take enforcement actions as described in the uniform grants rules at 45 CFR 75.371.
In the past several years, a number of states have taken actions to restrict participation by certain types of providers as subrecipients in the Title X Program, unrelated to the provider's ability to provide the services required under Title X. In at least several instances, this has led to disruption of services or reduction of services. Since 2011, 13 states have placed restrictions on or eliminated subawards with specific types of providers based on reasons unrelated to their ability to provide required services in an effective manner. When the state health department is a Title X recipient, these restrictions on subrecipient participation can apply. In several instances, these restrictions have interfered with the “capacity [of the applicant] to make rapid and effective use of [Title X federal] assistance.” PHSA sec. 1001(b). Moreover, states that restrict eligibility of subrecipients have caused limitations in the geographic distribution of services, and decreased access to services through trusted and qualified providers.
States have restricted subrecipients from participating in the Title X program in several ways. Some states have employed a tiered approach to compete or distribute Title X funds, whereby entities such as comprehensive primary care providers, state health departments, or community health centers receive a preference in the distribution of Title X funds. This approach effectively excludes providers focused on reproductive health from receiving funds, even though they have been shown to provide higher quality services, such as preconception services, and accomplish Title X programmatic objectives more effectively.
In New Hampshire, in 2011, the New Hampshire Executive Council voted not to renew the state's contract with a specific provider that was contracted to provide Title X family planning services for more than half of the state. To restore services to clients in the unserved part of the state, HHS issued an emergency replacement grant, but there was significant disruption in the delivery of services, and for approximately three months, no Title X services were available to potential clients in a part of the state.
Most recently, in 2016 Florida enacted a law that would have gone into effect on July 1, 2016, prohibiting the state from making Title X subawards to certain family planning providers.
None of these state restrictions are related to the subrecipients' ability to effectively deliver Title X services. The previously mentioned exclusions are based either on non-Title X health services offered or other activities the providers conduct with non-federal funds, or because they are a certain type of provider. The Title X program provides family planning services based on “the number of patients to be served, the extent to which family planning services are needed locally, the relative need of the applicant, and its capacity to make rapid and effective use of [Title X Federal] assistance.” PHSA sec. 1001(b). Allowing project recipients, including states and other entities, to impose restrictions on subrecipients that are unrelated to the ability of subrecipients to provide Title X services in an effective manner has been shown to have an adverse effect on access to Title X services and therefore the fundamental goals of the Title X program.
Litigation concerning these restrictions has led to inconsistency across states in how recipients may choose subrecipients. As the restrictions vary, so have the statutory and constitutional issues in the cases. For example, in
At least two other U.S. Courts of Appeal have specifically held that Title X prohibits state laws that have restrictive subrecipient eligibility criteria.
These and other appellate courts have also considered First Amendment issues in adjudicating state restrictions, though not all cases have involved Title X funds. Some courts have concluded certain state restrictions do not violate the Constitution.
The Department is proposing to amend the regulations at 42 CFR 59.3 to require that project recipients that do not provide services directly may not prohibit subrecipients from participating on bases unrelated to their ability to provide Title X services effectively. The proposed rule will maintain uniformity in administration, ensure consistency of subrecipient participation across grant awards, improve the provision of services to populations in appropriate geographic areas, and guarantee Title X resources are allocated on the basis of fulfilling Title X family planning goals. The deleterious effects already caused by restrictions in several states as outlined above justify a rule in order to fulfill the purpose of Title X. The proposed rule helps fulfill the declared purpose of providing a broad range of family planning methods and services to populations most in need. Nothing in the statute supports giving discretion to project recipients to make eligibility restrictions that may adversely affect accessibility of Title X services.
The proposed rule will further Title X's purpose by protecting access of intended beneficiaries to Title X service providers that offer a broad range of acceptable and effective family planning methods and services. Title X regulations at 42 CFR 59.7 lay out the criteria for how the Department decides which family planning projects to fund and in what amount, based on the Department's judgment as to which projects best promote the purposes of the statute. Among these criteria are: The number of patients to be served (in particular, low-income patients), as well as the adequacy of the applicant's facilities and staff.
Data show that specific provider types with a reproductive health focus provide a broader range of contraceptive methods on-site, and are more likely to have protocols that assist clients with initiating and continuing to use methods without barriers.
In April 2014, CDC and the Office of Population Affairs released clinical recommendations, “
Another study, using nationally representative survey data, examined four aspects of the scope and quality of family planning service delivery before release of the QFP: The scope of family planning services provided, contraceptive methods provided onsite, written contraceptive counseling protocols, and youth-friendly services. In assessing the scope of family planning services provided, providers were asked about the provision of the following services in the past three months: Pregnancy diagnosis and counseling, contraceptive services, basic infertility services, STD screening, and preconception health care. To assess contraceptive methods provided onsite, questions were asked regarding the provision of a range of reversible methods on site, as well as the presence of contraceptive counseling protocols. Again, as described in the previous study, results were tabulated according to the type of publicly funded site where services were provided. Across all four aspects, the focused reproductive health providers provided services that were broader in scope and of higher quality across all four aspects of family planning service delivery.
Data show that restricting specific providers of Title X services has harmful effects on access to family planning services and is linked with increased pregnancy rates that are not in line with population-wide trends. In addition, studies have shown that state actions to exclude specific family
Denying participation by family planning providers that can provide effective services has also resulted in populations in certain geographic areas being left without a Title X provider for an extended period of time, such as in New Hampshire in 2011 (detailed previously). In some cases, excluded providers do not have the administrative capacity to directly apply for and manage a Title X grant, as was the case in Kansas when specific family planning providers were excluded by the state from participation in the Title X Program. The data show that restrictions hurt the priority population for publicly funded family planning services, and that providers that are focused specifically on family planning service provision generally provide better access and higher quality family planning services, which is the purpose of the program.
Under the proposed rule, all project recipients that do not provide the services directly must only choose subrecipients on the basis of their ability to effectively deliver Title X required services.
Under the proposed rule, a tiering structure—described above—would not be allowable unless it could be shown that the top tier provider (
The Department seeks comments on several issues. The Department is cognizant of administrative burdens on both itself and project recipients that could result from the proposed changes, as discussed further below in the Regulatory Impact Analysis, and seeks comment on how to minimize them. Additionally, the Department seeks input on whether other portions of the Title X rules might need to be amended to conform to this rule regarding the selection of subrecipients. We invite comments on the utility of requiring compliance reports or other records demonstrating a project recipient's criteria for selecting providers, or whether a complaint-driven process would promote the same goals more efficiently. Project recipients found out of compliance would have all the same rights to appeal adverse determinations under the proposed rule as they do any other agency decision. For example, after voluntary compliance avenues have failed and the Department determines to terminate the grant, grantees could appeal wrongful termination claims through the Departmental Appeals Board process. 42 CFR 59.10.
While the Department is also aware of the scope of the proposed rule, it does not believe it will interfere with other generally applicable state laws. If, for example, a state law requires certain wage rates, or addresses family leave or non-discrimination, this rule will not interfere with that law, since all subrecipients will be similarly situated as to that state law. Only those laws which directly distinguish among Title X providers for reasons unrelated to their ability to deliver services would be implicated, and then, only if the state chooses to continue to apply for funding. The Department seeks comment on the regulatory language and ways it may be seen as interacting with other state law provisions.
While specifically seeking comment on the issues outlined above, the Department invites comments on any other issues raised by the proposed regulation.
HHS has examined the impact of this proposed rule under Executive Order
Executive Order 12866 directs 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 is supplemental to and reaffirms the principles, structures, and definitions governing regulatory review as established in Executive Order 12866. HHS expects that this proposed rule will not have an annual effect on the economy of $100 million or more in at least 1 year. Therefore, this rule will not be an economically significant regulatory action as defined by Executive Order 12866.
The Regulatory Flexibility Act (RFA) requires agencies that issue a regulation to analyze options for regulatory relief of small businesses if a rule has a significant impact on a substantial number of small entities. The RFA generally defines a “small entity” as (1) a proprietary firm meeting the size standards of the Small Business Administration; (2) a nonprofit organization that is not dominant in its field; or (3) a small government jurisdiction with a population of less than 50,000 (States and individuals are not included in the definition of “small entity”). For similar rules, HHS considers a rule to have a significant economic impact on a substantial number of small entities if at least 5 percent of small entities experience an impact of more than 3 percent of revenue. HHS anticipates that the proposed rule will not have a significant economic impact on a substantial number of small entities.
Section 202(a) of the Unfunded Mandates Reform Act of 1995 requires that agencies prepare a written statement, which includes an assessment of anticipated costs and benefits, before proposing “any rule that includes any Federal mandate that may result in the expenditure by State, local, and tribal governments, in the aggregate, or by the private sector, of $100,000,000 or more (adjusted annually for inflation) in any one year.” The current threshold after adjustment for inflation is $146 million, using the most current (2015) implicit price deflator for the gross domestic product. This proposed rule would not trigger the Unfunded Mandate Reform Act because it will not result in any expenditure by states or other government entities.
Since 2011, 13 states have taken actions to restrict participation by certain types of providers as subrecipients in the Title X program based on factors unrelated to the providers' ability to provide the services required under Title X effectively. In at least several instances, this has led to disruption of services or reduction of services where a public entity, such as a state health department, holds a Title X grant and makes subawards to subrecipients for the provision of services. In response to these actions, this proposed rule requires that any Title X recipient subawarding funds for the provision of Title X services not prohibit a potential subrecipient from participating for reasons unrelated to its ability to provide services effectively.
Certain states have policies in place which limit access to high quality family planning services by restricting specific types of providers from participating in the Title X program. These policies, and varying court decisions on their legality, has led to uncertainty among grantees, inconsistency in program administration, and diminished access to services for Title X target populations. These restrictive state policies exclude certain providers for reasons unrelated to their ability to provide Title X services effectively. As a result of these state policies, providers previously determined by Title X grantees to be effective providers of family planning services have been excluded from participation in the Title X program. In turn, the exclusion of these high quality providers is associated with a reduction in the quality of family planning services, the number of Title X service sites, reduced geographic availability of Title X services, and fewer Title X clients served.
Reducing access to Title X services has many adverse effects. Title X services have a dramatic effect on the number of unintended pregnancies and births in the United States. For example, services provided by Title X-funded sites helped prevent an estimated 1 million unintended pregnancies in 2010 which would have resulted in an estimated 501,000 unplanned births.
In addition to reducing access to the Title X program, these policies may reduce the quality of Title X services, as described previously. Research has shown that providers with a reproductive health focus provide services that more closely align with the statutory and regulatory goals and purposes of the Title X Program. In particular, these entities provide a broader range of contraceptive methods on-site, are more likely to have written protocols that assist clients with initiating and continuing contraceptive use without barriers, disproportionately serve more clients in need of family planning services, and provide higher quality services as stipulated in national recommendations, “
Policies that eliminate specific reproductive health providers for
This proposed rule directly prohibits Title X recipients that subaward funds for the provision of Title X services from excluding an entity from participating for reasons unrelated to its ability to provide services effectively. Following the implementation of policies this regulation proposes to reverse, states shifted funding away from family planning service providers previously determined to be most effective. We believe that this proposed rule is likely to undo these effects, resulting in a shift toward service providers previously determined to be the most effective. To the extent that a state may come into compliance with this regulation by relinquishing its Title X grant or not applying for a Title X grant, other organizations could compete for Title X funding to deliver services in areas where a state entity previously subawarded funds for the delivery of Title X services. In turn, we expect that this will reverse the associated reduction in access to Title X services and deterioration of outcomes for affected populations.
Research has shown that every grant dollar spent on family planning saves an average of $7.09 in Medicaid-related expenditures.
Following publication of a final rule that builds upon this proposal and public comments, OPA will work to educate Title X program recipients and applicants about the requirement to not prohibit a potential subrecipient from participating for reasons unrelated to its ability to provide services effectively. OPA will send a letter summarizing the change to current recipients of Title X funds and post the letter to its Web site. OPA will also add conforming language to its related forthcoming funding opportunity announcements (FOAs). OPA has existing channels for disseminating information to stakeholders. Therefore, based on previous experience, the Department estimates that preparing and disseminating these materials will require approximately one to three percent of a full-time equivalent OPA employee at the GS-12 step 5 level. Based on federal wage schedule for 2016 in the Washington, DC area, GS-12 step 5 level corresponds to an annual salary of $87,821. We double this salary cost to account for overhead and benefits. As a result, we estimate a cost of approximately $1,800—$5,300 to disseminate information following publication of the final rule.
We expect that, if this proposed rule is finalized, stakeholders including grant applicants and recipients potentially affected by this proposed policy change will process the information and decide how to respond. This change will not affect the majority of current recipients, and as a result the majority of current recipients will spend very little time reviewing these changes before deciding that no change in behavior is required. For the states that currently hold Title X grants and have laws or policies restricting Title X subrecipients, the final rule would implicate state law or policy. State agencies that currently restrict subawards would need to carefully revise their current practices in order to comply with these changes.
We estimate that current and potential recipients will spend an average of one to two hours processing the information and deciding what action to take. We note that individual responses are likely to vary, as many parties unaffected by these changes will spend a negligible amount of time in response to these changes. According to the U.S. Bureau of Labor Statistics,
Public funding for family planning services is likely to shift to providers that see a higher number of patients and provide higher quality services. Increases in the quantity and quality of Title X service utilization will lead to fewer unintended pregnancies, improved health outcomes, reduced Medicaid costs, and increased quality of life for many individuals and families. The proposed rule's impacts will take place over a long period of time, as it will allow for the continued flow of
We estimate costs of $11,400-$24,600 in the first year following publication of the final rule, and suggest that this rule is beneficial to society in increasing access to and quality of care. We note that the estimates provided here are uncertain.
We carefully considered the option of not pursuing regulatory action. However, as discussed previously, not pursuing regulatory action means allowing the continued provision of Title X funds to subrecipients for reasons other than their ability to provide high quality family planning services. This, in turn, means accepting reductions in access to and quality of services to populations who rely on Title X. As a result, we chose to pursue regulatory action.
Executive Order 13132 establishes certain requirements that an agency must meet when it promulgates a final rule that imposes substantial direct requirement costs on state and local governments, preempts state law, or otherwise has federalism implications. The Department particularly invites comments from states and local governments, and will consult with them as needed in promulgating the final rule. While we do not believe this rule will cause substantial economic impact on the states, it will implicate some state laws if states wish to apply for federal Title X funds. Therefore, the following federalism impact statement is provided.
E.O. 13132 establishes the need for Federal agency deference and restraint in taking action that would curtail the policy-making discretion of the states or otherwise have a substantial impact on the expenditure of state funds. The proposed rule simply sets the conditions to be eligible for federal funding for both public and private entities. The proposed rule will not have a significant impact on state funds as, by law, project grants must be funded with at least 90 percent federal funds. 42 U.S.C. 300a-4(a). Furthermore, states that are the project recipients of Title X grants are not required to issue subawards at all. However, those that choose to do so would be required to do so in a manner that considers only the ability of the subrecipients to meet the statutory objectives.
States remain entirely free to set their policies and funding preferences as to family planning services paid for with state funds. While this proposed rule will eliminate the ability of states to restrict subawards with Title X funds for reasons unrelated to the statutory objectives of Title X, they remain free to set their own preferences in providing state-funded family planning services. The rule does not impose any additional requirements on states in their performance under the Title X grant, other than to avoid discrimination in making subawards, should they choose to make such subawards. And states remain free to apply for federal program funds, subject to the eligibility conditions. For the reasons outlined above, the proposed rule is designed to achieve the objectives of Title X related to providing effective family planning services to program beneficiaries with the minimal intrusion on the ability of project recipients to select their subrecipients.
The amendments proposed in this rule will not impose any additional data collection requirements beyond those already imposed under the current information collection requirements which have been approved by the Office of Management and Budget.
Birth control, Family planning, Grant programs.
Therefore, under the authority of section 1006 of the Public Health Service Act as amended, and for the reasons stated in the preamble, the Department proposes to amend 42 CFR part 59 as follows:
42 U.S.C. 300a-4.
(a) Any public or nonprofit private entity in a State may apply for a grant under this subpart.
(b) No recipient making subawards for the provision of services as part of its Title X project may prohibit an entity from participating for reasons unrelated to its ability to provide services effectively.
Defense Acquisition Regulations System, Department of Defense (DoD).
Proposed rule; extension of comment period.
DoD is proposing to amend the Defense Federal Acquisition Regulation Supplement (DFARS) to implement a section of the National Defense Authorization Act for Fiscal Year 2012 that revises the sections of title 10 of the United States Code (U.S.C.) that address technical data rights and validation of proprietary data restrictions. The comment period on the proposed rule is extended 16 days.
For the proposed rule published on June 16, 2016 (81 FR 39481), submit comments by September 30, 2016.
Submit comments identified by DFARS Case 2012-D022, using any of the following methods:
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Comments received generally will be posted without change to
Ms. Amy G. Williams, telephone 571-372-6106.
On June 16, 2016, DoD published a proposed rule in the
• Adds special provisions for handling technical data that are necessary for segregation and reintegration activities;
• Codifies and revises the policies and procedures regarding deferred ordering of technical data necessary to support DoD major systems or subsystems, weapon systems, or noncommercial items or processes;
• Expands the period in which DoD can challenge an asserted restriction on technical data from 3 years to 6 years;
• Rescinds changes to 10 U.S.C. 2320 from the NDAA for FY 2011; and
• Codifies Government purpose rights as the default rights for technical data related to technology developed with mixed funding.
The comment period for the proposed rule is extended 16 days, from September 14, 2016 to September 30, 2016, to provide additional time for interested parties to comment on the proposed DFARS changes.
Government procurement.
Surface Transportation Board.
Advance notice of proposed rulemaking.
The Surface Transportation Board (Board) is seeking comments and suggestions through this Advance Notice of Proposed Rulemaking (ANPR) regarding the Board's effort to develop a new rate reasonableness methodology for use in very small disputes, which would be available to shippers of all commodities.
Comments are due by November 14, 2016. Reply comments are due by December 19, 2016.
Comments and replies may be submitted either via the Board's e-filing format or in the traditional paper format. Any person using e-filing should attach a document and otherwise comply with the instructions at the “E-FILING” link on the Board's Web site, at “
Copies of written comments and replies will be posted to the Board's Web site and will be available for viewing and self-copying at the Board's Public Docket Room, Room 131. Copies will also be available (for a fee) by contacting the Board's Chief Records Officer at (202) 245-0238 or 395 E Street SW., Washington, DC 20423-0001.
Allison Davis at (202) 245-0378. Assistance for the hearing impaired is available through the Federal Information Relay Service (FIRS) at (800) 877-8339.
In the Interstate Commerce Act, Congress charged the Board with protecting the public from unreasonable pricing by freight railroads, while fostering a sound, safe, and efficient rail transportation system by allowing carriers to earn adequate revenues.
By decision served in
The Board has considered all of the written comments and oral testimony received in Docket No. EP 665 (Sub-No. 1).
Before discussing ideas for use in a new rate reasonableness methodology, we will discuss the Board's existing rate reasonableness standards and the comments received in Docket No. EP 665 (Sub-No. 1).
Where a railroad has market dominance—
In carrying out its regulatory functions, the Board is guided by the rail transportation policy set forth at 49 U.S.C. 10101. And in assessing the reasonableness of rail rates, it must also give due consideration to the “Long-Cannon” factors contained in 49 U.S.C. 10701(d)(2)(A)-(C). The Board must recognize that rail carriers should have an opportunity to earn “adequate revenues,” which are defined as those that are sufficient—under honest, economical, and efficient management—to cover operating expenses, support prudent capital outlays, repay a reasonable debt level, raise needed equity capital, and otherwise attract and retain capital in amounts adequate to provide a sound rail transportation system. 49 U.S.C. 10701(d)(2), 10704(a)(2).
As part of ICCTA, Congress added a new provision to the rail transportation policy calling for the “expeditious handling and resolution of all proceedings.” 49 U.S.C. 10101(15). Congress further instructed the Board to establish procedures for rail rate challenges in particular, including “appropriate measures for avoiding delay in the discovery and evidentiary phases of such proceedings.” 49 U.S.C. 10704(d). Congress directed the Board to “establish a simplified and expedited method for determining the reasonableness of challenged rail rates in those cases in which a full stand-alone cost presentation is too costly, given the value of the case.” 49 U.S.C. 10701(d)(3). In the Surface Transportation Board Reauthorization Act of 2015, Public Law 114-110, 129 Stat. 2228 (2015), Congress directed the Board to “initiate a proceeding to assess procedures that are available to parties in litigation before courts to expedite such litigation and the potential application of any such procedures to rate cases.” 129 Stat. 2228. That proceeding is currently pending before the Board.
Under the theory of “constrained market pricing” (CMP), adopted by the agency in 1985 to judge the reasonableness of rail freight rates, a captive shipper should not be required to pay more than is necessary for the carrier involved to earn adequate revenues, nor should it pay more than is necessary for efficient service, and a captive shipper should not bear the costs of any facilities or services from which it derives no benefit.
A SAC analysis seeks to determine whether a complainant is bearing costs resulting from inefficiencies or costs associated with facilities or services from which it derives no benefit. The SAC analysis does this by simulating the competitive rate that would exist in a “contestable market.”
The agency recognized that the SAC methodology adopted in
In
Under the Three-Benchmark method, the reasonableness of a challenged rate is determined by examining that rate in relation to the following three benchmark figures, each of which is expressed as a revenue-to-variable cost (R/VC) ratio: (1) Revenue Shortfall Allocation Method (RSAM), which measures the average markup over variable cost that the defendant railroad would need to charge all of its “potentially captive” traffic (traffic priced above the 180% R/VC level) in order for the railroad to earn adequate revenues as measured by the Board under 49 U.S.C. 10704(a)(2); (2) R/VC
In Three-Benchmark cases, each party simultaneously proposes an initial comparison group, and, after critiquing the other side's proposal, a “final offer” comparison group. After receiving simultaneous rebuttal filings, the Board selects without adjustment one of the two “final offer” comparison groups. Each movement in the comparison group is adjusted by a revenue need adjustment factor, which is the ratio of RSAM ÷ R/VC
Since
There is no monetary limit on relief for a complainant that elects to use the SAC or Simplified-SAC methods,
The shipper community argues that the Board's current rate review processes are not useable to test the reasonableness of agriculture commodity rail rates. Shippers argue that the Board's existing methodologies are cost-prohibitive. (ARC Opening 21-22; NGFA Opening 13-15; AAI Reply 2.) For example, NGFA argues that even the simplest of the Board's rate reasonableness methodologies, the Three-Benchmark approach, is ineffective because railroad defendants raise numerous expert-intensive “other relevant factor” arguments and arguments for the use of current waybill data in the possession of the defendant railroad, which greatly increase the complexity and costs of those cases. (NGFA Opening 15.)
Even if the Three-Benchmark methodology were not cost prohibitive, shippers argue that a comparison group approach is ineffective for agricultural commodities because carriers have applied “across-the-board” pricing. (ARC Opening 23; NGFA Opening 15; AAI Reply 2.) Specifically, shippers claim that carriers use their market power to impose a uniformly high rate across-the-board for certain commodities or groups of commodities. (ARC Opening 23; NGFA Opening 15.) As a result, shippers argue that the R/VC
NGFA also argues that SAC and Simplified-SAC are inaccessible because many grain shippers are on low-density rural branch lines or secondary lines, and the Board's holding regarding cross-subsidies in
Shippers propose both modifications to the existing methodologies and new processes for rate review. Regarding the existing methodologies, several shipper groups argue for changes to the Three-Benchmark methodology. ARC argues that the comparison groups in the Three-Benchmark method should include non-defendant traffic for grain and grain products shippers because limiting comparison groups to defendant traffic eliminates a significant amount of traffic with similar demand characteristics. (ARC Opening 22-23,
Shippers also argue that comparison groups in the Three-Benchmark methodology should include non-captive traffic,
In addition, ARC proposes two adjustment factors that the Board could apply in rate challenges related to grain shipments. First, it proposes a Grain Cost Adjustment Factor (GCAF), which would be applied to the Board's URCS Phase III costing program for railroad movements of grain and grain products. ARC claims the GCAF would more accurately reflect the fact that these movements generally have certain lower costs than the system average costs, including switching, crew, locomotive, and car costs. (ARC Opening, V.S. Fauth 7.) ARC also proposes an export grain rate adjustment that takes into account the economic relationship between grain prices and grain exports. (ARC Opening, V.S. Fauth 30-31.)
ARC and NGFA also each propose new rate review processes. ARC sets forth a “Two-Benchmark” approach for revenue adequate railroads, which would eliminate the R/VC
NGFA proposes an alternative method called the Ag Commodity Maximum Rate Methodology (ACMRM). (NGFA Opening 27-31, V.S. Crowley 6-17.) Under ACMRM, the issue traffic would be compared against all railroads (not just the defendant railroad) and movements with R/VC ratios less than 180% (although, the maximum reasonable rate produced by the analysis would be subject to the statutory 180% floor). (NGFA Opening 28-29, V.S. Crowley 9-11.) Under NGFA's proposal, the comparison group would be based on certain default factors, including a mileage band, commodity type, railcar type, railcar ownership, and movement type. (NGFA Opening, V.S. Crowley 6-7.) ACMRM also would eliminate the confidence interval adjustment and the “other relevant factors” analysis so that captive agriculture commodity rate cases could be decided quickly and at reasonable cost. (NGFA Opening 31.) The rate prescription period would be 5 years, and there would be no limits on the amount of relief that the complaining shipper or group of shippers could receive if a rate challenge is successful. (NGFA Opening 31.) ACMRM also includes a commodity-specific Revenue Adequacy Adjustment Factor, which would be used to adjust the R/VC ratio of each movement in the comparison group to account for the revenue adequacy status of each railroad. (NGFA Opening 31.)
Carriers, on the other hand, argue that grain rates are not unreasonable and the Board's existing rules provide ample opportunity for grain shippers to pursue rate relief. (BNSF Opening 1, 26-29; UP Opening 19-20.) Carriers cite the lack of grain rate litigation as evidence that most grain rates are reasonable or not subject to the Board's jurisdiction (R/VC ratios below 180%, contract movements, or exempt commodities). (BNSF Opening 26-29; UP Opening 20; AAR Reply 9-10; CSXT Reply 4; NSR Reply 24-25.) According to carriers, rail rates for grain are effectively constrained by competition from truck, barge, and other railroads, as well as by the competitive global market for grain sales. (BNSF Opening 17-23, 27-29; UP Opening 15-20; CSXT Reply 2-3.)
Carriers also argue that the Board has already sufficiently addressed shippers' concerns by limiting its market dominance inquiry to direct competition (
Generally, carriers advocate maintaining the Board's current rate review processes and ask the Board to reject the modifications and alternatives set forth by the shipper community. (
Carriers also find flaws in ARC's proposal. Specifically, they argue that ARC's proposal would create a disincentive for railroads to expand competitive traffic through good business practices and would result in an overall degradation of rail service, contrary to the public interest. (AAR Reply 21-22; BNSF Reply 31; UP Reply 21-22, 37.) UP further argues that ARC's proposal is inconsistent with the competitive market principles embodied in the Board's governing statute and with basic railroad economics because it disregards the railroad's need for differential pricing to recover their joint and common costs. (UP Reply 35;
The carriers also argue that modifications to the Three-Benchmark approach, such as inclusion of non-defendant or non-captive traffic in the comparison group, lack sound economic support. Railroads dispute the idea of including non-defendant traffic in comparison groups, arguing that comparisons that include traffic moving on other railroads do not accurately establish the appropriate contribution to the defendant railroad's fixed costs. (AAR Reply 17-18; BNSF Reply 27.) BNSF further argues that including all traffic in the proposed comparison group eliminates a railroad's ability to engage in differential pricing, contrary to the basic economics of the railroad industry. (BNSF Reply 23.) NSR notes that expanding the comparison group would not simplify rate reasonableness determinations, but rather would increase the cost and complexity of the Three-Benchmark approach by requiring examination and evidence based on rates and costing from other railroads. (NSR Reply 29.)
Likewise, carriers oppose the inclusion of non-captive traffic in the comparison group. According to NSR, there is no basis for comparing traffic over which the railroad is potentially market dominant to traffic over which the railroad is not market dominant by statute. (NSR Reply 17.) According to BNSF and UP, by seeking to include in the comparison group traffic with competitive alternatives, NGFA seeks to eliminate a railroad's ability to engage in differential pricing, contrary to the basic economics of the railroad industry. (BNSF Reply 23; UP Reply 24-26.) According to BNSF and UP, including movements with R/VC ratios below 180% in the comparison group will also lead to a ratcheting down of R/VC ratios until the 180% R/VC ratio becomes the rate ceiling. (BNSF Reply 24-25; UP Reply 23-24.)
USDA also provided comment, arguing that a new approach is necessary and warranted, and should be explored, and that agricultural shippers require specifically designed rail rate challenge procedures. (USDA Opening 2.) USDA argues that none of the current rail rate appeals procedures are suitable for agricultural shippers because they are much too costly, complex, and time consuming, and agricultural shippers do not move large enough quantities to justify the cost of these procedures. (
Based on the comments and testimony received in this proceeding, the Board is persuaded that the existing rate review processes present accessibility challenges not only for small shippers of grain, but also for small shippers of any commodity. The Board recognizes that, for small disputes, the litigation costs required to bring a case under the Board's existing rate reasonableness methodologies, even the Board's most simplified method, Three-Benchmark, can quickly exceed the value of the case. The Board appreciates receiving the alternative methodologies proposed by ARC and NGFA; however, we are not convinced that the alternative methodologies as proposed strike the proper balance between the Board's statutory goals of providing captive shippers meaningful access to regulatory remedies for unreasonable rail rates, while permitting railroads to earn a reasonable return on their investments so that they will have the resources to make the investment needed to continue to serve the transportation needs of their customers.
Although the Board has concerns with the proposals set forth by ARC and NGFA, several of the ideas that parties have raised as part of these methodologies, or on how to modify the Three-Benchmark methodology, warrant further exploration. In particular, if the Board could develop a process that reduces the litigation burden on parties even more than the simplest existing rate reasonableness methodology, it could achieve the goal of creating more accessible rate review processes for small disputes where even a Three-Benchmark case would be too costly, given the value of the case. Accordingly, we are considering developing a set of procedures that could comprise a new comparison-based rate reasonableness methodology for use by shippers of all commodities in very small disputes. The Board is considering a new process that would entail the following key elements.
First, the process would include a preliminary screen that would limit its application to shippers that are more likely to be considered captive and to have rates that are outliers. Such a screen might allow for the Board to make market dominance and rate reasonableness determinations based on an abbreviated evidentiary process. Second, the process would contain a comparison-based analysis in which the Board develops an initial comparison group and then allows parties to propose modifications. By having the Board set the initial comparison group, based on pre-determined criteria, the evidentiary process could be simplified, as parties would only have to present evidence on modifications rather than creating their own comparison groups (as is currently the case in Three-Benchmark cases). Third, the process would contain other procedural modifications that help expedite and streamline the comparison-based assessment. In particular, the Board is considering ideas such as limiting discovery, establishing mandatory disclosures, limiting the length of filings, and establishing an evidentiary hearing in lieu of rebuttal evidence. Finally, because the process would only be intended for small disputes, the Board would limit the amount of relief available.
It is the Board's goal that procedures evolving from this ANPR would shorten the case timeline and reduce litigation costs, while achieving the same objectives as the existing rate methodologies and minimizing the loss of precision. The Board is guided by the concerns raised during the public comment period in Docket No. EP 665 (Sub-No. 1), namely that the Board's current rate review processes are cost-prohibitive for grain and other shippers with small disputes, and by the rail transportation policy set forth at 49 U.S.C. 10101. The Board must balance
We are seeking comment in a new docket, Docket No. EP 665 (Sub-No. 2), as we believe this methodology should be available to shippers of all commodities, not just grain, with small disputes. Many of the concerns raised about the accessibility of the Board's existing rate reasonableness procedures are general in nature. Indeed, some commenters expressly acknowledged that such concerns may be equally applicable to shippers of other commodities (
The Board seeks comment on whether the procedures set forth in this decision—or variations on these procedures—would provide a reasonable yet accessible methodology for use in very small rate disputes. The Board also welcomes comments on other means the Board could implement to keep the costs of a new process low.
Although the concerns expressed by the agricultural community in Docket No. EP 665 (Sub-No. 1) and elsewhere have been instrumental in informing the Board of the need for a new approach, we do not believe that a new methodology should be limited to small shippers of only agricultural products. Instead, as discussed above, we are exploring how best to develop a new methodology that would be available to shippers of all commodities with small disputes.
We are considering limiting this methodology, however, to disputes involving only Class I rail carriers. The Board does not envision that the new process would apply to purely local movements of a Class II or Class III carrier, which would be consistent with the Three-Benchmark methodology.
The new methodology the Board is considering would utilize a comparison group approach to determine the reasonableness of the challenged traffic's rate. Under such an approach, the issue traffic would be compared against a comparison group of similar traffic drawn from the preceding four years of data in the Board's Waybill Sample. In order to reduce litigation costs, the Board would determine an initial comparison group based on default parameters established in a rulemaking, rather than having parties develop and tender a proposed comparison group, as is done in Three-Benchmark cases.
The Board is considering the following default parameters for selecting the initial comparison group and seeks comment on each.
(a) The movement is within a +/− 15% mileage band around the actual miles travelled by the challenged traffic,
(b) the movement is of the same shipment type (
(c) the movement is of a commodity classified under the same Standard Transportation Commodity Code (STCC).
With respect to the last of these parameters, the Board believes that the most appropriate method of determining which commodities should be used in the comparison group is to use the same five-digit STCC as the issue traffic. Commodities listed at the five-digit STCC generally should be similar enough in characteristics for inclusion in the comparison group. However, certain other commodities differ at an even more granular level, such as chemicals (
The Board invites comment on these comparison group procedures, and also on which commodities would be appropriately compared at the seven-digit STCC. The Board also invites comment on whether the Board should consider expanding the comparison of commodities beyond the five- or seven-
The Board invites comments on this possible approach of broadening the STCC limitation in this manner and on whether a 20-observation minimum would be an appropriate requirement.
The Board notes, however, that, including non-defendant traffic in the comparison group likely would necessitate third-party discovery (as to whether cost structure differences between carriers make certain movements inappropriate for the comparison group) and would affect whether parties would be required to hire outside counsel to manage the receipt of confidential Waybill Sample data from other carriers.
The Board recognizes that it is essential that any procedures comprising a new rate reasonableness methodology be both more streamlined and less costly than the Board's existing rate review processes. As a result, the Board is considering the procedures set forth below with the goal of achieving a shortened procedural schedule and including measures addressing concerns that the existing procedures for challenging a rate are cost-prohibitive.
Given the abbreviated evidentiary presentation in a simplified, lower-cost process, the Board is considering requiring that challenged traffic meet certain threshold criteria in order to be eligible to be reviewed under the new methodology. This preliminary screen would seek to identify those movements for which truck transportation alternatives are unlikely and the rates are significant outliers, allowing the Board to make market dominance and rate reasonableness determinations based on the abbreviated evidentiary submissions described below. The issue traffic would, of course, have to be priced above the 180% R/VC level, which is the statutory floor for regulatory rail rate intervention.
Additionally, the Board is considering the following criteria for the issue traffic as a preliminary screen and seeks comment on each of the following potential criteria.
The Board also is considering limiting discovery in order to reduce litigation costs for very small disputes. In particular, the Board could require that parties file certain initial disclosures with their complaint and answer. Concurrent with the filing of its complaint, the complainant could be required to disclose the nine standard inputs for the URCS Phase III costing program.
With regard to qualitative market dominance, the complainant could also be required to make certain required disclosures. For example, in a verified statement by a company official, the complainant could be required to submit: (i) A statement that the issue traffic has not moved more than a de minimis amount on alternative transportation modes between the same origin and destination within a certain number of years, and (ii) a statement whether the complainant has made any inquiries to, or received any responses from, alternative transportation providers for the issue traffic within a certain number of years, including copies of any such communications (if available).
The defendant could likewise be required to provide initial disclosures to the complainant concurrent with filing its answer. Like the complainant, the defendant could be required to produce its preliminary estimate of the variable cost of the challenged movement, using the unadjusted figures produced by the URCS Phase III costing program. To the extent that the defendant disagreed with any of the URCS inputs provided in the complaint, it could also be required to provide the inputs that it used. The defendant could also be required to provide to the Board and the complainant all documents that it relied upon to determine the inputs used in the URCS Phase III costing program. Finally, the defendant could be required to disclose the actual route miles for the issue traffic and provide supporting data to the Board and, upon request, to the complainant.
Another limit on discovery could be to limit the amount or type of party-initiated discovery or eliminating such discovery altogether, given that the need for such information would be significantly reduced by the simplifications discussed here. For example, the fact that the initial comparison group would be set by the Board (based on defined criteria) and not the parties would eliminate one need for the parties to seek discovery. In terms of limiting discovery, in preparing its answer, the defendant could reply with information that is either disclosed by the complainant in its complaint or opening evidence, or developed independently by the defendant, but the defendant would not be permitted to seek additional discovery from the complainant. Likewise, the complainant would not be permitted to serve any discovery on the defendant in preparation of its evidentiary submissions.
Additionally, as noted above, if the Board were to include non-defendant traffic in the comparison group, the Board is concerned that it would be required to permit discovery from the non-defendant carriers whose traffic is included in the comparison group. In that case, the Board could consider limits, such as five interrogatories (including subparts) and five document requests (including subparts) per party for each non-defendant carrier, and could require that such discovery be completed by a specific number of days. Such third-party discovery would occur prior to the submission of each party's evidence.
We therefore seek comment on whether to mandate certain initial disclosures and, if so, what those disclosures should be, and any other ways to limit or eliminate party-initiated discovery in a new, streamlined comparison group methodology for small disputes.
The Board seeks comment on the following procedures it is considering for use in a new simplified rate reasonableness methodology.
In its opening evidence, the complainant would also have the opportunity to state whether the initial, Board-determined comparison group is appropriate. The complainant may propose adjustments to the default initial comparison group and present “other relevant factors” evidence, such as a density adjustment or PTC adjustment, among others.
The defendant would also have the opportunity to respond to the complainant's arguments regarding the appropriateness of any proposed adjustments to the default initial comparison group. The defendant could also propose its own adjustments to the default initial comparison group and set forth “other relevant factors” evidence.
We recognize that, even with a word limit and limits on or exclusion of discovery, allowing parties' presentations to include “other relevant factors” evidence could substantially increase the cost and time required to prepare for submission of a case. For instance, we do not expect that the examples noted above—a density adjustment or PTC adjustment—could be easily calculated by a small entity without hiring outside consultants. Therefore, the Board invites comment on the advisability of allowing parties' presentations to include “other relevant factors” evidence. The Board also invites parties to comment on the appropriateness of sequential as opposed to simultaneous filings of each party's evidence, a reasonable time-frame for considering qualitative market dominance arguments, a reasonable word or page limit for opening and reply evidence, and any other issues related to the filing of opening and reply evidence.
Under the procedures being considered as described in this decision, the Board would issue two decisions. First, following receipt of the defendant's answer, the Board would issue a preliminary decision in which the Board would (i) resolve any URCS Phase III input disputes, (ii) determine whether the challenged traffic meets the preliminary screen based on the initial comparison group, and (iii) make a final determination on whether the defendant carrier has quantitative market dominance over the movements at issue. In the event that the issue traffic fails to meet the preliminary screen based on the initial comparison group, the Board would dismiss the complaint without prejudice. For challenged traffic that satisfies the preliminary screen, the Board would provide the initial comparison group data pursuant to the standardized confidentiality agreements previously filed by the parties.
Second, following the evidentiary hearing, the Board would issue a final decision addressing qualitative market dominance and rate reasonableness. With regard to qualitative market dominance, the Board expects that its qualitative market dominance analysis could be far more limited than in other rate reasonableness methodologies given the preliminary screen and initial disclosure requirements. In particular, because the screen would help identify movements that are more likely to be captive, the Board envisions
If the Board finds that the defendant carrier has qualitative market dominance over the challenged traffic, the Board would address each of the parties' arguments regarding the appropriateness of the initial comparison group and adjustments thereto. If the comparison group is adjusted, the Board would reevaluate the challenged traffic to ensure that it continues to satisfy the preliminary screen based on the adjusted comparison group. In the event that the issue traffic fails to meet the preliminary screen based on the adjusted comparison group, the Board would dismiss the proceeding with prejudice to the complainant challenging the same movement under the new method for a certain period, but without prejudice to the complainant challenging the same movement under one of the Board's other rate review processes.
For the rate reasonableness determination, the Board would compute the maximum R/VC ratio for the issue traffic in a manner similar to the Three-Benchmark analysis, although with a potential modification. Specifically, the Board would apply a revenue need adjustment—which is the ratio of RSAM ÷ R/VC
However, the Board is considering departing from Three-Benchmark precedent with respect to the revenue need adjustment. As noted, in a Three-Benchmark case, each movement in the final comparison group is adjusted by a revenue need adjustment factor. During the public comment period in Docket No. EP 665 (Sub-No. 1), NGFA proposed the creation of an alternative revenue need adjustment factor—a Revenue Adequacy Adjustment Factor (RAAF), which would be commodity-specific and would account for the revenue adequacy status of each railroad. NGFA argues that the RAAF is superior to the Board's current revenue need adjustment factor because it takes into consideration the amount of issue commodity traffic that is ostensibly captive to the railroad and allocates the burden of a revenue need adjustment factor to those commodities that provide the most revenue. (NGFA Opening, V.S. Crowley 12.) There may be merit to NGFA's suggestion that our current revenue need adjustment factor could be adapted to reflect the differences in rates and revenues carriers obtain from various commodity groups. Thus, the Board is considering whether it could make the revenue need adjustment factor commodity specific. However, if the Board were to adopt a commodity specific revenue need adjustment factor, we must ensure that we establish the most appropriate formula.
Therefore, we seek comment on whether the Board should modify its revenue need adjustment factor to be commodity-specific, and if so, how we can effectively disaggregate the existing RSAM on a commodity-by-commodity basis. Because some commodities have a higher R/VC ratio than others, the adjusted revenue need adjustment factor should allocate the revenue shortfall in ways that reflect the different demand elasticities faced by different commodities. However, the weighted average of all commodities when totaled should equal the overall RSAM.
We believe that, on average, differences in demand elasticities are reflected in R/VC ratios—those with higher R/VC ratios tend to enjoy less direct and indirect competition while those with lower R/VC ratios tend to enjoy somewhat more competition. In an individual proceeding, we would consider applying a commodity-specific RSAM where the resulting figure reflects this intuition. We believe such a mark-up could be done in a manner consistent with Ramsey pricing principles.
While Ramsey pricing represents the most efficient way to price above marginal cost, reliance on pure Ramsey pricing clashes with the Long-Cannon factors because it would not maximize the revenue contribution from traffic with more-elastic demand (competitive traffic) before calling on traffic with less-elastic demand (captive traffic) to make a differentially higher revenue contribution. For these reasons, the Board has not adopted pure Ramsey pricing theory. Rather, in SAC cases, the Board allocates stand-alone costs
Because of the abbreviated nature of the process described in this decision, the Board is considering limiting relief available under this process. The ideas presented in the ANPR describe a process that would be significantly more streamlined than the process required to bring a Three-Benchmark case. As such, the relief available under this method would likewise need to be significantly less than the relief available under the Three-Benchmark approach. The Board invites parties to comment on the amount of relief that should be available and why that amount of relief would be appropriate.
The limit on relief would apply to the difference between the challenged rate and the maximum lawful rate, whether in the form of reparations, a rate prescription, or a combination of the two. Any rate prescription would automatically terminate once the complainant has exhausted the relief available. Thus, the actual length of the prescription may be less than the prescription period if the shipper ships a large enough volume of traffic so that the relief is used up in a shorter time. The complainant would be barred from bringing another complaint against the same rate for the remainder of the prescription period.
Where the shipper exhausts all of its relief before the end of the prescription period, the carrier's rate making freedom would be restored with a regulatory safe harbor at the challenged rate for the remainder of the prescription period, with appropriate adjustments for inflation using the rail cost adjustment factor, adjusted for inflation and productivity (RCAF-A).
Because this ANPR does not impose or propose any requirements, and instead seeks comments and suggestions for the Board to consider in possibly developing a subsequent proposed rule, the requirements of the Regulatory Flexibility Act of 1980, 5 U.S.C. 601-612 (RFA) do not apply to this action. Nevertheless, as part of any comments submitted in response to this ANPR, parties may include comments or information that could help the Board assess the potential impact of a subsequent regulatory action on small entities pursuant to the RFA.
The Board seeks public input on how best to establish a new rate reasonableness process for use in small disputes, available to shippers of all commodities, to provide shippers with small disputes meaningful access to regulatory relief in those cases where even a Three-Benchmark case is too costly, given the value of the case. The Board welcomes comments from interested parties on the issues and considerations presented in this decision.
1. Comments are due by November 14, 2016. Reply comments are due by December 19, 2016.
2. A copy of this decision will be served upon the Chief Counsel for Advocacy, Office of Advocacy, U.S. Small Business Administration.
3. Notice of this decision will be published in the
4. This decision is effective on its service date.
By the Board, Chairman Elliott, Vice Chairman Miller, and Commissioner Begeman. Vice Chairman Miller commented with a separate expression.
Today's decision is an important step forward for the Board. Despite the agency's well-intentioned efforts over the years to create simpler, timelier, and less costly rate dispute processes, I believe that they are still inaccessible to shippers with small disputes, denying them the opportunity to obtain rate relief. This decision focuses on filling that gap in our processes.
While I applaud the Board for today's action, we still have work to do. Even if the Board is able to develop an abbreviated rate case methodology that can be used by shippers with small rate disputes, it will not resolve the concerns that have been raised about the SAC test. The methodology here is only intended to address small rate disputes for shippers that meet certain criteria. As such, the Board still needs to consider alternatives to the SAC test for shippers with larger disputes. A reasonable starting point to address this issue would be for the Board to publicly release the report prepared by our outside consultant on SAC alternatives and conduct a hearing to obtain feedback and reaction from our stakeholders on the report's conclusions.
The following appendix will not appear in the Code of Federal Regulations.
The Board received written comment and testimony from the following parties in Docket No. EP 665 (Sub-No. 1).
Opening comments were received from:
Reply comments were received from:
Testimony at the June 10, 2015 hearing was received from:
Supplemental comments were received from:
Fish and Wildlife Service, Interior.
Proposed rule; reopening of comment period; availability of peer review and supplementary documents.
We, the U.S. Fish and Wildlife Service (Service), announce the reopening of the public comment period on our March 11, 2016, proposed rule to revise the List of Endangered and Threatened Wildlife, under the authority of the Endangered Species Act, by removing the Greater Yellowstone Ecosystem population of grizzly bears (
We will consider comments received or postmarked on or before October 7, 2016. Comments submitted electronically using the Federal eRulemaking Portal (see
You may submit comments by one of the following methods:
(1)
(2)
We request that you send comments only by the methods described above. We will post all comments on
Wayne Kasworm, Acting Grizzly Bear Recovery Coordinator, U.S. Fish and Wildlife Service, Grizzly Bear Recovery Office, University Hall, Room #309, University of Montana, Missoula, MT 59812; telephone 406-243-4903. For Tribal inquiries, contact Ivy Allen, Native American Liaison, U.S. Fish and Wildlife Service; telephone: 303-236-4575. Persons who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 800-877-8339.
We will accept written comments and information during this reopened comment period on the March 11, 2016, proposed rule (81 FR 13174) to remove the Greater Yellowstone Ecosystem (GYE) population of grizzly bears (
You may submit your comments and materials concerning the proposed rule by one of the methods listed in
Comments and materials we receive, as well as supporting documentation we used in preparing the proposed rule, will be available for public inspection on
On March 11, 2016, we published a proposed rule to revise the List of Endangered and Threatened Wildlife in title 50 of the Code of Federal Regulations at 50 CFR 17.11(h), under the authority of the Endangered Species Act of 1973, as amended (16 U.S.C. 1531
1. Suspension of all discretionary mortality inside the Demographic Monitoring Area (DMA), except if required for human safety, if the model-averaged Chao2 population estimate falls below 600.
2. Suspension of grizzly bear hunting inside the DMA if total mortality limits for any sex/age class (as per tables 1, 2, and 3 in the proposed rule) are met at any time during the year (the mortality limits in these tables are reiterated in table 1 in this document, below).
3. Prohibition of recreational harvest of female grizzly bears with young.
4. In a given year, allowance of discretionary mortality only if nondiscretionary mortality (
5. Provisions to ensure that any mortality that exceeds total mortality limits in any year will be subtracted from that age/sex class total mortality limit for the following year to ensure that long-term mortality levels remain within prescribed limits inside the DMA.
We noted that regulatory mechanisms containing these provisions must be in place in each State for delisting to occur because the adequacy or inadequacy of those regulatory mechanisms help inform us whether a species, once delisted, will remain recovered. The ESA requires the Service to consider existing regulatory mechanisms when making listing determinations.
Montana, Wyoming, and Idaho recently finalized such regulatory mechanisms governing potential hunting seasons for grizzly bear. These three States also approved the Tri-State MOA, which outlines their coordinated plans for grizzly bear management and allocates discretionary mortality of grizzly bears in the GYE between the three States. The three States approved the Tri-State MOA on the following dates: Wyoming, on May 11, 2016; Montana, on July 13, 2016; and Idaho, on August 8, 2016.
Montana, Wyoming, and Idaho each used a different regulatory method, appropriate to their respective legal processes, to enact their State rules governing human-caused grizzly bear mortality. Montana's Fish and Wildlife Commission adopted hunting regulations that outline the structure of a possible future grizzly bear hunting season on July 13, 2016 (Montana Fish and Wildlife Commission, 2016). Montana's Fish and Wildlife Commission also approved the Tri-State MOA (Wyoming Game and Fish Commission, Montana Fish and Wildlife Commission, & Idaho Fish and Game Commission, 2016). Before adopting these regulations and the MOA, Montana released the drafts of these documents for public comment and review. The Montana Fish and Wildlife Commission adopted the hunting regulations and the MOA in the same manner that it adopts other regulations, with public notice and comment. In the Service Assessment below, we assume the MOA and hunting regulations are regulatory in nature.
On July 8, 2016, the Wyoming Game and Fish Commission approved a regulatory framework that “provides for the management of grizzly bears in Wyoming to ensure a recovered population” (Wyoming Game and Fish Commission, 2016). The Wyoming Game and Fish Commission invited the
Idaho's Fish and Game Commission issued a proclamation relating to the limit of the take of grizzly bears in the GYE on August 8, 2016 (Idaho Fish and Game Commission, 2016). Idaho Code Section 36-105 authorizes the Idaho Fish and Game Commission to use proclamations, which “have full force and effect as law,” as a means of “setting any season or limit on numbers, size, sex or species of wildlife classified by the commission as game animals.” Since grizzly bears are classified as game animals in Idaho Administrative Code 13.01.06.100.01e, the Idaho Fish and Game Commission may use a proclamation to establish binding limits on the take of grizzly bears (Idaho Administrative Code 13.01.06.100.01e).
Table 2 cross-references the aforementioned requirements in the proposed rule with the content of each State's regulations. The full text of the State regulations and the Tri-State MOA can be found on the Internet at
The Service has reviewed the recently finalized State regulations governing the management of grizzly bears in the GYE and the regulation of human-caused mortality (including the Tri-State MOA, Montana's Grizzly Bear Hunting Regulations, Chapter 67 of Wyoming's Game and Fish Commission regulations, and Idaho's Fish and Game Commission Proclamation). Our preliminary assessment is that these documents are consistent with the letter or intent of the regulatory requirements regarding human-caused mortality that we outlined in the proposed rule. Thus, based on our review, we believe the regulatory framework in Montana, Wyoming, and Idaho, in combination with the Tri-State MOA, will maintain a recovered population of grizzly bears in the GYE. We are accepting public comments on these State regulations and our preliminary assessment that they provide adequate regulatory mechanisms such that we can conclude that the population no longer meets the definition of threatened under the Endangered Species Act.
In accordance with our joint policy on peer review published in the
A complete list of references cited is available: on the Internet at
The authority for this action is the Endangered Species Act of 1973, as amended (16 U.S.C. 1531
Agricultural Marketing Service, USDA.
Notice of public meeting.
Pursuant to the Federal Advisory Committee Act, the Agricultural Marketing Service (AMS) is announcing a meeting of the Fruit and Vegetable Industry Advisory Committee (Committee). The meeting is being convened to examine the full spectrum of fruit and vegetable industry issues and to provide recommendations and ideas to the Secretary of Agriculture on how the U.S. Department of Agriculture (USDA) can tailor programs and services to better meet the needs of the U.S. produce industry. The meeting is open to the public. This notice sets forth the schedule and location for the meeting.
Tuesday, October 25, 2016, from 8:30 a.m. to 5:00 p.m. Eastern Time, and Wednesday, October 26, 2016, from 8:30 a.m. to 1:00 p.m., Eastern Time.
The Committee meeting will be held in the Tidewater I&II Conference Room at the Hyatt Regency Crystal City Hotel @Ronald Reagan National Airport, 2799 Jefferson Davis Highway, Arlington, Virginia, 22202.
Pamela Stanziani, Designated Federal Official, USDA, AMS, Specialty Crops Program; Telephone: (202) 720-3334; Email:
Pursuant to the Federal Advisory Committee Act (FACA) (5 U.S.C. App.), the Secretary of Agriculture (Secretary) established the Committee in 2001, to examine the full spectrum of issues faced by the fruit and vegetable industry and to provide suggestions and ideas to the Secretary on how USDA can tailor its programs to meet the fruit and vegetable industry's needs. The Committee was re-chartered in July 2015, for a two-year period.
AMS Deputy Administrator for the Specialty Crops Program, Charles Parrott, serves as the Committee's Manager. Representatives from USDA mission areas and other government agencies affecting the fruit and vegetable industry are periodically called upon to participate in the Committee's meetings as determined by the Committee. AMS is giving notice of the Committee meeting to the public so that they may attend and present their views. The meeting is open to the public.
Agenda items may include, but are not limited to, welcome and introductions, administrative matters, progress reports from committee working group chairs and/or vice chairs, potential working group recommendation discussion and proposal, and presentations by subject matter experts.
Forest Service, USDA.
Notice of meeting.
The Uinta-Wasatch-Cache Resource Advisory Committee (RAC) will meet in South Jordan, Utah. The committee is authorized under the Secure Rural Schools and Community Self-Determination Act (the Act) and operates in compliance with the Federal Advisory Committee Act. The purpose of the committee is to improve collaborative relationships and to provide advice and recommendations to the Forest Service concerning projects and funding consistent with Title II of the Act. RAC information can be found at the following Web site:
The meeting will be held on September 28, 2016, from 6:00 p.m.-8:30 p.m.
All RAC meetings are subject to cancellation. For status of meeting prior to attendance, please contact the person listed under
The meeting will be held at the Uinta-Wasatch-Cache Forest Service Office, Room #314, 857 West South Jordan Parkway, South Jordan, Utah. The meeting will also be available via teleconference. For anytone who would like to attend via teleconferenc, please visit the Web site listed in the
Written comments may be submitted as described under
Loyal Clark, RAC Coordinator by phone at 801-999-2113, or via email at
Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information
The purpose of the meeting is to review and recommend project proposals.
The meeting is open to the public. The agenda will include time for people to make oral statements of three minutes or less. Individuals wishing to make an oral statement should request in writing by September 14, 2016, to be scheduled on the agenda. Anyone who would like to bring related matters to the attention of the committee may file written statements with the committee staff before or after the meeting. Written comments and requests for time to make oral comments must be sent to Loyal Clark, RAC Coordinator, Uinta-Wasatch-Cache National Forest, 857 West South Jordan Parkway, South Jordan, Utah 84095; by email to
United States Commission on Civil Rights.
Notice of Commission Business Meeting.
Notice is hereby given, pursuant to the provisions of the rules and regulations of the U.S. Commission on Civil Rights, and the Federal Advisory Committee Act (FACA), that a Business Meeting of the U.S. Commission on Civil Rights will be convened at 10 a.m. on Friday, September 9, 2016.
Friday, September 9, 2016, at 10 a.m. EST.
National Place Building, 1331 Pennsylvania Ave. NW., 11th Floor, Suite 1150, Washington, DC 20425 (Entrance on F Street NW.).
Brian Walch, Communications and Public Engagement Director. Telephone: (202) 376-8371; TTY: (202) 376-8116; Email:
This business meeting is open to the public.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
Effective September 7, 2016.
Jeff Pedersen, AD/CVD Operations, Office IV, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230, telephone: (202) 482-2769.
On February 18, 2015, the Department of Commerce (the Department) published in the
Pursuant to 19 CFR 351.213(d)(1), the Department will rescind an
The Department will instruct U.S. Customs and Border Protection (“CBP”) to assess antidumping duties on all appropriate entries. For the companies for which this review is rescinded, antidumping duties shall be assessed at rates equal to the cash deposit of estimated antidumping duties required at the time of entry, or withdrawal from warehouse, for consumption, in accordance with 19 CFR 351.212(c)(1)(i). The Department intends to issue appropriate assessment instructions directly to CBP 15 days after publication of this notice.
This notice serves as the only reminder to importers whose entries will be liquidated as a result of this rescission notice, 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 assumption that the reimbursement of antidumping duties occurred and the subsequent assessment of double antidumping duties.
This notice also serves as a reminder to parties subject to administrative protective orders (“APO”) of their responsibility concerning the return or destruction of proprietary information disclosed under an 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 terms of an APO is a violation which is subject to sanction.
This notice is issued and published in accordance with section 751(a)(1) of the Act and 19 CFR 351.213(d)(4).
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 certain hot-rolled carbon steel flat products from India (hot-rolled steel). The period of review (POR) is December 1, 2014, through November 30, 2015. This review covers four companies, Ispat Industries Ltd. (Ispat), JSW Steel Ltd. (JSW), JSW Ispat Steel Ltd. (JSW Ispat), and Tata Steel Ltd. (Tata). We preliminarily determine that Ispat, JSW, JSW Ispat, and Tata had no entries of subject merchandise during the POR. Interested parties are invited to comment on these preliminary results.
George McMahon or Eric Greynolds, AD/CVD Operations Office III, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-1167 and (202) 482-6071, respectively.
The merchandise subject to this order is certain hot-rolled carbon steel flat products from India. The merchandise subject to this order is currently classifiable in the Harmonized Tariff Schedule of the United States (HTSUS) at subheadings: 7208.10.15.00, 7208.10.30.00, 7208.10.60.00, 7208.25.30.00, 7208.25.60.00, 7208.26.00.30, 7208.26.00.60, 7208.27.00.30, 7208.27.00.60, 7208.36.00.30, 7208.36.00.60, 7208.37.00.30, 7208.37.00.60, 7208.38.00.15, 7208.38.00.30, 7208.38.00.90, 7208.39.00.15, 7208.39.00.30, 7208.39.00.90, 7208.40.60.30, 7208.40.60.60, 7208.53.00.00, 7208.54.00.00, 7208.90.00.00, 7211.14.00.90, 7211.19.15.00, 7211.19.20.00, 7211.19.30.00, 7211.19.45.00, 7211.19.60.00, 7211.19.75.30, 7211.19.75.60, and 7211.19.75.90.
The Department conducted this review in accordance with section 751(a)(2) of the Tariff Act of 1930, as amended (the Act). For a full description of the methodology underlying our preliminary results, see the Preliminary Decision Memorandum. The Preliminary Decision Memorandum is a public document and is on file electronically via Enforcement and Compliance's Antidumping and Countervailing Duty Centralized Electronic Service System (ACCESS). ACCESS is available to registered users at
Ispat, JSW, JSW Ispat, and Tata submitted timely-filed certifications that they had no exports, sales, or entries of subject merchandise during the POR,
Upon issuance of the final results of this administrative review, the Department shall determine, and CBP shall assess, antidumping duties on all appropriate entries, in accordance with 19 CFR 351.212. The Department intends to issue assessment instructions to CBP 15 days after publication of the final results of this review.
In accordance with the Department's “automatic assessment” practice,
We intend to issue instructions to CBP 15 days after publication of the final results of this review.
The following cash deposit requirements will be effective upon publication of the notice of final results of administrative review for all shipments of subject merchandise entered, or withdrawn from warehouse, for consumption on or after the publication of the final results of this administrative review, as provided by section 751(a)(2) of the Act: (1) The cash deposit rates for respondents noted above, which claimed no shipments, will remain unchanged from the rates assigned to the companies in the most recently completed review of the companies; (2) for merchandise exported by producers or exporters not covered in this administrative review but covered in a prior segment of the proceeding, the cash deposit rate will continue to be the company-specific rate published for the most recently completed segment of this proceeding; (3) if the exporter is not a firm covered in this review, a prior review, or the original investigation, but the producer is, the cash deposit rate will be the rate established for the most recently completed segment of this proceeding for the producer of the subject merchandise; and (4) the cash deposit rate for all other producers or exporters will continue to be 38.72 percent, the all-others rate established in the less-than-fair value investigation, as amended. These cash deposit requirements, when imposed, shall remain in effect until further notice.
Pursuant to 19 CFR 351.309(c)(1)(ii), interested parties may submit cases 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.
Interested parties who wish to request a hearing must submit a written request to the Assistant Secretary for Enforcement and Compliance, U.S. Department of Commerce, using Enforcement and Compliance's ACCESS system within 30 days of publication of this notice.
Unless the deadline is extended pursuant to section 751(a)(3)(A) of the Act, the Department will issue the final results of this administrative review, including the results of our analysis of the issues raised by the parties in their case briefs, within 120 days after issuance of these preliminary results.
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 increase the subsequent assessment of the antidumping duties by the amount of antidumping duties reimbursed.
These preliminary results of 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.
The Department of Commerce (the Department) preliminarily determines that critical circumstances exist for imports of certain carbon and alloy steel cut-to-length plate (CTL plate) from certain producers and exporters from Austria, Belgium, Brazil, Taiwan, and Turkey.
Effective September 7, 2016.
Edythe Artman at (202) 482-3931 (Austria), Elizabeth Eastwood at (202) 482-3874 (Belgium), Mark Kennedy at (202) 482-7883 (Brazil), Steve Bezirganian at (202) 482-1131 (Korea-AD), John Corrigan at (202) 482-7438 (Korea-CVD), Tyler Weinhold at (202) 482-1121 (Taiwan), or Dmitry Vladimirov at (202) 482-0665 (Turkey), AD/CVD Operations, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 1401 Constitution Avenue NW., Washington, DC 20230.
In response to petitions filed on April 8, 2016,
Pursuant to 19 CFR 351.206(c)(2), the petitioners requested that the Department issue a preliminary affirmative determination of critical circumstances on an expedited basis. In accordance with sections 703(e)(1) and 733(e)(1) of the Act, because the petitioners submitted their critical circumstances allegations more than 20 days before the scheduled date of the final determination, the Department must promptly issue preliminary critical circumstances determinations.
Section 703(e)(1) of the Act provides that the Department will determine that critical circumstances exist in CVD investigations if there is a reasonable basis to believe or suspect: (A) That “the alleged countervailable subsidy” is inconsistent with the Agreement on Subsidies and Countervailing Measures (SCM Agreement) of the World Trade Organization, and (B) that “there have been massive imports of the subject merchandise over a relatively short period.” Section 733(e)(1) of the Act provides that the Department will preliminarily determine that critical circumstances exist in AD investigations if there is a reasonable basis to believe or suspect: (A)(i) That “there is a history of dumping and material injury by reason of dumped imports in the United States or elsewhere of the subject merchandise,” or (ii) that “the person by whom, or for whose account, the merchandise was imported knew or
To determine whether an alleged countervailable subsidy is inconsistent with the SCM Agreement, in accordance with section 703(e)(1)(A) of the Act, the Department considered the evidence currently on the record of the Korea CVD investigation. Specifically, as determined in our initiation checklist, the following subsidy programs, alleged in the petition and supported by information reasonably available to the petitioners, appear to be either export contingent or contingent upon the use of domestic goods over imported goods, which would render them inconsistent with the SCM Agreement: Korean Export-Import Bank Short-Term Export Credits; Korean Export-Import Bank Export Factoring; Korean Export-Import Bank Export Loan Guarantees; Korean Export-Import Bank Trade Bill Rediscounting Program; Korea Development Bank (KDB) Short-Term Discounted Loans for Export Receivables; Loans under the Industrial Base Fund; Korea Trade Insurance Corporation (K-SURE) Short-Term Export Credit Insurance; and K-SURE Export Credit Guarantees.
Therefore, the Department preliminarily determines for purposes of this critical circumstances determination that there are alleged subsidies in the Korea CVD investigation that are inconsistent with the SCM Agreement.
In order to determine whether there is a history of dumping pursuant to section 733(e)(1)(A)(i) of the Act, the Department generally considers current or previous AD orders on subject merchandise from the country in question in the United States and current orders imposed by other countries with regard to imports of the same merchandise.
To determine whether importers knew or should have known that exporters were selling at less than fair value, we typically consider the magnitude of dumping margins, including margins alleged in petitions.
To determine whether importers knew or should have known that there was likely to be material injury, we typically consider the preliminary injury determinations of the International Trade Commission (ITC).
In determining whether there have been “massive imports” over a “relatively short period,” pursuant to sections 703(e)(1)(B) and 733(e)(1)(B) of the Act, the Department normally compares the import volumes of the subject merchandise for at least three months immediately preceding the filing of the petition (
Thus, because the petitions were filed on April 8, 2016, in order to determine whether there has been a massive surge in imports for each cooperating mandatory respondent, the Department compared the total volume of shipments during the period April 2016 through June 2016 with the volume of shipments during the preceding three-month period of January 2016 through March 2016. For Brazil and Turkey, because the mandatory respondents refused to participate in the investigations, we determine, on the basis of adverse facts available, that there has been a massive surge in imports. For “all-others,” the Department relied on GTA data which demonstrates that the volume of CTL plate from Brazil and Turkey increased massively in the three month period April 2016 through June 2016 when compared to the prior three-month period.
For the cooperating respondents in the investigations on Austria, Belgium, Korea, and Taiwan, we compared the total volume of shipments during the period April 2016 through June 2016 with the volume of shipments during the preceding three-month period of January 2016 through March 2016. For “all-others,” the Department compared GTA data for the same time periods.
• Austria (A-433-812): Voestalpine Grobblech GmbH, voestalpine Steel & Service Center GmbH, Bohler Edelstahl GmbH & Co. KG, BOHLER Bleche GmbH & Co. KG, Bohler Uddeholm Corporation, and Strudell Industries, Inc. (collectively, Voestalpine);
• Belgium (A-423-812): Industeel Belgium SA and NLMK Clabecq
• Taiwan (A-583-858): China Steel Corporation and All-Other producers/exporters.
Based on the criteria and findings discussed above, we preliminarily determine that critical circumstances exist with respect to imports of CTL plate shipped by certain producers/exporters. Our findings are summarized as follows.
We will issue final determinations concerning critical circumstances when we issue our final countervailing duty and less than fair value determinations. All interested parties will have the opportunity to address these determinations in case briefs to be submitted after completion of the preliminary countervailing duty and less than fair value determinations.
In accordance with sections 703(f) and 733(f) of the Act, we will notify the ITC of our determinations.
In accordance with section 733(e)(2) of the Act, because we preliminarily found that critical circumstances exist with regard to exports made by certain producers and/or exporters, if we make an affirmative preliminary determination that sales at less than fair value have been made by these same producers/exporters at above
Because we preliminarily found that critical circumstances do not exist with respect to the CVD investigation of CTL plate from Korea, we will not order any retroactive suspension of liquidation under section 703(e)(2) of the Act in the event of an affirmative preliminary countervailing duty determination in this investigation.
This notice is issued and published pursuant to section 777(i) of the Act and 19 CFR 351.206(c)(2).
The Department of Commerce will submit to the Office of Management and Budget (OMB) for clearance the following proposal for collection of information under the provisions of the Paperwork Reduction Act (44 U.S.C. Chapter 35).
National Marine Fisheries Service (NMFS) and the North Pacific Fishery Management Council developed regulations under the Magnuson-Stevens Act and the American Fisheries Act (AFA) to govern commercial fishing for Bering Sea and Aleutian Islands Management Area (BSAI) pollock according to the requirements of the AFA. These regulations are necessary to achieve the AFA's objective of decapitalization and rationalization of the BSAI pollock fishery.
With exceptions noted below, all participants in the AFA pollock fishery are already permitted and the permits are issued with an indefinite expiration date. The permanent AFA permits are: AFA catcher vessel, AFA catcher/processor, AFA mothership, and AFA inshore processor. The permit exceptions are issued annually—the inshore vessel cooperative permit and inshore vessel contract fishing permit. In addition, the AFA vessel replacement application may be submitted to NMFS at any time.
This information collection request may be viewed at reginfo.gov. Follow the instructions to view Department of Commerce collections currently under review by OMB.
Written comments and recommendations for the proposed information collection should be sent within 30 days of publication of this notice to
Notice of meeting.
The Advisory Committee on Commercial Remote Sensing (ACCRES) will meet September 21, 2016. The meeting will be held, in accordance with Section 10(d) of the Federal Advisory Committee Act, 5 U.S.C. App. 2, and with Section 552b(c)(1) of Title 5, United States Code.
The meeting is scheduled as follows: September 21, 2016, 9:00 a.m.-4:00 p.m. The meeting will be open to the public from 9:00 a.m.-12:00 p.m. and a closed session will be held from 1:00 p.m.-4:00 p.m.
The public portion of the meeting will be held at The Aerospace Corporation, Gambit Auditorium, Room L0037, 14745 Lee Road, Chantilly, VA 20151.
Tahara Dawkins, NOAA/NESDIS/CRSRA, 1335 East West Highway, Room 8260, Silver Spring, Maryland 20910; (301) 713-3385,
As required by section 10(a)(2) of the Federal Advisory Committee Act, 5 U.S.C. App. (1982) and its implementing regulations,
Pursuant to 41 CFR 102-3.150, the notice for this meeting is being given fewer than 15 calendar days prior to the meeting due to the following exceptional circumstances: (i) The review and clearance process for the Notice of Determination to partially close the meeting, which is required under 41 CFR 102-3.155, involved administrative and timing limitations, including in this instance the additional delay resulting from the Labor Day holiday; and (ii) due to preexisting commitments and statutorily-established deadlines, delaying the September 21, 2016 meeting would make it substantially more difficult for ACCRES to complete its required consultation on the report mandated by Section 202 of the
The first part of the meeting will be open to the public pursuant to Section 10(a)(1) of the Federal Advisory Committee Act, 5 U.S.C. App. 2 (FACA). During the open portion of the meeting, the Committee will receive updates on NOAA's Commercial Remote Sensing Regulatory Affairs activities. The Committee will also be available to receive public comments on its activities.
The second part of the meeting will be closed to the public pursuant to Section 10(d) of FACA as amended by Section 5(c) of the Government in Sunshine Act, Public Law 94-409 and in accordance with Section 552b(c)(1) of Title 5, United States Code, which authorizes closure of meetings likely to disclose matters that are “specifically authorized under criteria established by Executive order to be kept secret in the interests of national defense or foreign policy and . . . in fact properly classified pursuant to such Executive order.” The part of the meeting which will be closed will address the ongoing review and implementation of the 2015 U.S. Commercial Space Launch Competitiveness Act and related national security, foreign policy concerns and future technology
The meeting is physically accessible to people with disabilities. Requests for special accommodations may be directed to ACCRES, NOAA/NESDIS/CRSRA, 1335 East West Highway, Room 8260, Silver Spring, Maryland 20910.
Any member of the public who plans to attend the open meeting should RSVP to Samira Patel at (301) 713-7077,
ACCRES expects that public statements presented at its meetings will not be repetitive of previously-submitted oral or written statements. In general, each individual or group making an oral presentation may be limited to a total time of five minutes. Written comments (provide at least 20 copies) sent to NOAA/NESDIS/CRSRA on or before September 21, 2016 will be provided to Committee members in advance of the meeting. Comments received too close to the meeting date will normally be provided to Committee members at the meeting.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of a public meeting.
The Gulf of Mexico Fishery Management Council will hold a meeting of its Ad Hoc Red Snapper Charter Advisory Panel (AP).
The meeting will convene Monday, September 26, 2016, from 1 p.m. to 5 p.m. and Tuesday, September 27, 2016, from 8:30 a.m. to 5 p.m.
The meeting will be held at the Doubletree New Orleans Airport hotel, located at 2150 Veterans Memorial Boulevard, Kenner, LA 70062; telephone: (504) 467-3111.
Dr. Ava Lasseter, Anthropologist, Gulf of Mexico Fishery Management Council;
The items of discussion on the agenda are as follows:
The Agenda is subject to change, and the latest version along with other meeting materials will be posted on the Council's file server. To access the file server, the URL is
The meeting will be webcast over the internet. A link to the webcast will be available on the Council's Web site,
Although other non-emergency issues not on the agenda may come before the Advisory Panel for discussion, in accordance with the Magnuson-Stevens Fishery Conservation and Management Act, those issues may not be the subject of formal action during this meeting. Actions of the Advisory Panel will be restricted to those issues specifically identified in the agenda and any issues arising after publication of this notice that require emergency action under Section 305(c) of the Magnuson-Stevens Fishery Conservation and Management Act, provided the public has been notified of the Council's intent to take action to address the emergency.
This meeting is physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aids should be directed to Kathy Pereira at the Gulf Council Office (see
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; public meetings.
The Gulf of Mexico Fishery Management Council (Council) will hold two Coral Grant Stakeholder Engagement Meetings to educate
These meetings will be held September 26 and 27, 2016; and will begin at 6 p.m. and will conclude no later than 9 p.m. For specific dates and times, see
The public documents can be obtained by contacting the Gulf of Mexico Fishery Management Council, 2203 N. Lois Avenue, Suite 1100, Tampa, FL 33607; (813) 348-1630 or on their Web site at
Douglas Gregory, Executive Director, Gulf of Mexico Fishery Management Council; telephone: (813) 348-1630.
Council staff will give a brief presentation on coral reef habitats in the Gulf of Mexico and present information on potential coral protection mechanisms. Following the presentation, Council staff will open the meeting for questions and public comments on proposed areas that may warrant Habitat Area of Particular Concern designation. The schedule is as follows:
These meetings are physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aids should be directed to Kathy Pereira (see
16 U.S.C. 1801
United States Patent and Trademark Office, Commerce.
Notice.
In conformance with the Civil Service Reform Act of 1978, the United States Patent and Trademark Office announces the appointment of persons to serve as members of its Performance Review Board.
Director, Human Capital Management, Office of Human Resources, United States Patent and Trademark Office, P.O. Box 1450, Alexandria, VA 22313-1450.
Anne Mendez at (571) 272-6173.
The membership of the United States Patent and Trademark Office Performance Review Board is as follows:
Alternates
10 a.m. EDT, Thursday, September 8, 2016.
CFTC Headquarters Lobby-Level Hearing Room, Three Lafayette Centre, 1155 21st Street NW., Washington, DC.
Open.
The Commission will hold this meeting to consider two final rules and a comparability determination. The agenda for this meeting is available to the public and posted on the Commission's Web site at
Christopher J. Kirkpatrick, Secretary of the Commission, 202-418-5964.
Bureau of Consumer Financial Protection.
Notice and request for comment.
In accordance with the Paperwork Reduction Act of 1995 (PRA), the Consumer Financial Protection Bureau (Bureau) is proposing a new generic information collection plan titled, “Generic Information Collection Plan for Surveys Using the Consumer Credit Panel.”
Written comments are encouraged and must be received on or
You may submit comments, identified by the title of the information collection, OMB Control Number (see below), and docket number (see above), by any of the following methods:
•
•
Documentation prepared in support of this information collection request is
Department of Education, Federal Student Aid.
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 November 7, 2016.
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
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 October 7, 2016.
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 NCES Information Collections at
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.
U.S. Department of Energy.
Notice of intent; correction.
The Department of the Energy (DOE) published a document in the
For further information on DOE's DUF
In the
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j. Columbia Basin Hydropower filed its request to use the Traditional Licensing Process on June 27, 2016. Columbia Basin Hydropower provided public notice of its request on August 4, 2016. In a letter dated August 31, 2016, the Director of the Division of Hydropower Licensing approved Columbia Basin Hydropower's request to use the Traditional Licensing Process.
k. With this notice, we are initiating informal consultation with the U.S. Fish and Wildlife Service and/or NOAA Fisheries under section 7 of the Endangered Species Act and the joint agency regulations thereunder at 50 CFR, part 402; and NOAA Fisheries under section 305(b) of the Magnuson-Stevens Fishery Conservation and Management Act and implementing regulations at 50 CFR 600.920. We are also initiating consultation with the Washington State Historic Preservation Officer, as required by section 106, National Historic Preservation Act, and the implementing regulations of the Advisory Council on Historic Preservation at 36 CFR 800.2.
l. With this notice, we are designating Columbia Basin Hydropower as the Commission's non-federal representative for carrying out informal consultation pursuant to section 7 of the Endangered Species Act and section 305(b) of the Magnuson-Stevens Fishery Conservation and Management Act; and consultation pursuant to section 106 of the National Historic Preservation Act.
m. Columbia Basin Hydropower filed a Pre-Application Document (PAD; including a proposed process plan and schedule) with the Commission, pursuant to 18 CFR 5.6 of the Commission's regulations.
n. A copy of the PAD is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site (
o. Register online at
This is a supplemental notice in the above-referenced proceeding Rutherford Farm, LLC's application for market-
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 September 20, 2016.
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 Stanford University 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 September 20, 2016.
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 corporate filings:
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:
Take notice that on August 29, 2016, pursuant to sections 206 and 306 of the Federal Power Act, 16 U.S.C. 824e and 825e (2012), and Rules 206 and 207(a)(5) of the Federal Energy Regulatory Commission's (Commission) Rules of Practice and Procedure, 18 CFR 385.206 and 207(a)(5) (2016), Dominion Resources Services, Inc. (Dominion) on behalf of Virginia Electric and Power Company (Complainant) filed a formal complaint against PJM Interconnection L.L.C. and PJM Settlement, Inc. (Respondents) alleging that Respondents violated its Open Access Transmission Tariff and Amended and Restated Operating Agreement by denying Dominion's request for a fuel cost adjustment resulting from the need to run Ladysmith Power Station Units 2-5 on back-up fuel oil rather than less expensive natural gas for reliability in real-time, all as more fully explained in the complaint.
Dominion certifies that copies of the complaint were served on the contacts for Respondent listed on the Commission's list of Corporate Officials.
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 and
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
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 expanded Freeport LNG Train 4 Project (Project) involving construction and operation of facilities by Freeport LNG Development, L.P. (Freeport LNG) in Brazoria County, Texas. The Commission will use this EA in its decision-making process to determine whether the planned project is in the public interest.
We
The comment period for the original scoping notice of the Project was from August 19, 2015 to September 18, 2015. This supplemental notice announces the opening of an additional scoping period the Commission will use to gather input from the new landowners potentially affected by changed to the planned Project, and inform interested agencies of the changes
As the modifications would affect new landowners; therefore, the Commission is issuing this supplemental notice to provide these new landowners an opportunity to comment on the Project. You can access detailed mapping of the modifications to the proposed pipeline route on the Commission's Web site (
Comments submitted during the original comment period have been made part of the docket and do not need to be resubmitted.
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, comments may be submitted in writing as described in the public participation section of this notice. Please note that comments on this supplemental notice should be filed with the Commission by October 3, 2016.
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.
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 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 (PF15-25-000) with your submission: Kimberly D. Bose, Secretary, Federal Energy Regulatory Commission, 888 First Street NE., Room 1A, Washington, DC 20426.
Freeport LNG intends to add a fourth liquefaction unit (Train 4), a supply pipeline, and associated infrastructure and utilities to Freeport LNG's natural gas Liquefaction Plant on Quintana Island in Brazoria County, Texas (Appendix 1, Figure 1). The Project would be located adjacent to the facilities authorized and currently under construction for the Phase II
Freeport LNG would expand the Pretreatment Plant that was approved under Docket CP12-509 (Appendix 1, Figure 2).
Freeport LNG indicates that the Train 4 Project would provide additional liquefaction capacity of approximately 5.1 million metric tonnes per annum (“mtpa”) of LNG for export. The additional liquefaction capacity provided by Train 4 would equate to a natural gas throughput capacity of approximately 0.74 billion cubic feet per day. This would enable Freeport LNG to respond favorably and proactively to short- and longer-term fluctuations in domestic and global gas markets.
The Freeport LNG Train 4 Project would consist of the following major components:
The general locations of project facilities are shown in Appendix 1.
The operational and construction footprint for the Train 4 Project would be primarily within Freeport LNG's previously disturbed areas authorized as part of the Liquefaction and Phase II Modification Projects (Docket Nos. CP12-29-000 and CP12-509-000) on Quintana Island in Brazoria County, Texas.
The Train 4 Project would affect about 558 acres during construction and the permanent operational footprint would be about 235 acres. Following construction, temporary construction areas would be restored and revert to former uses in areas other than the Quintana Island Terminal and Pretreatment Plant which have been disturbed by prior and present construction. These areas would be permanently maintained for industrial use.
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 an authorization to export natural gas under Section 3 of the Natural Gas Act. 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 address in the EA. We will consider all filed comments during the preparation of the EA.
In the EA we will discuss impacts that could occur as a result of the construction and operation of the planned project under these general headings:
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 EA.
The EA will present our independent analysis of the issues. The EA will be available in the public record through eLibrary. If we publish and distribute the EA to the public there will be an allotted comment period. We will consider all comments on the EA before we make 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 related to 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 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 Freeport LNG. This preliminary list of issues may change based on your comments and our analysis.
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.
If we publish and distribute the EA, 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).
Once Freeport LNG 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:
Instructions for becoming an intervenor are in the “Document-less Intervention Guide” under the “e-filing” link on the Commission's Web site. Please note that the Commission will not accept requests for intervenor status at this time. You must wait until the Commission receives a formal application for the project.
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 on August 30, 2016, pursuant to Rule 206 of the Federal Energy Regulatory Commission's (Commission) Rules of Practice and Procedure, 18 CFR 385.206, section 343.2 of the Commission's Rules Applicable to Oil Pipeline Proceedings, 18 CFR 343.2 (2016), and sections 1, 8, 9, 13(1), 15, and 16(1) of the Interstate Commerce Act (ICA), 49 U.S.C. app. §§ 1, 8, 9, 13(1), 15, & 16(1) (1988), Delta Air Lines, Inc., Atlas Air, Inc., and Polar Air Cargo Worldwide, Inc. (Complainants) filed a formal complaint against Enterprise TE Products Pipeline Company LLC, (Enterprise TEPPCO or Respondent) challenging the lawfulness of the existing jet fuel rates and charges for services on the interstate oil pipeline of Enterprise TEPPCO running from Lima, Ohio to Cincinnati/Northern Kentucky International Airport, as more fully explained in the complaint.
Complainants certify that copies of the complaint were served on the contacts for Enterprise TEPPCO as listed on the Commission's list of Corporate Officials.
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 and 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
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:
Take notice that the Commission has received the following Natural Gas Pipeline Rate and Refund Report 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 date(s). 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:
Federal Energy Regulatory Commission, DOE.
Notice of altered systems of records.
The Federal Energy Regulatory Commission (the Commission), under the requirements of the Privacy Act of 1974, 5 U.S.C. 552a, is publishing a description of an altered system of records (FERC-46).
Comments should be directed to the following address: Office of the General Counsel, General and Administrative Law Division, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The proposed revised system will become effective October 17, 2016 unless further notice is given. The Commission will publish a new notice if the effective date is delayed to review comments or if changes are made based on comments received. To be assured of consideration, comments should be received on or before October 7, 2016.
Kathryn Allen, Office of the General Counsel, General and Administrative Law Division, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8585.
The Privacy Act of 1974, 5 U.S.C. 552a, requires that each agency publish a notice of the existence and character of each new or altered “system of records.” 5 U.S.C. 552a(a)(5). This Notice identifies and describes the Commission's altered systems of records. A copy of this report has been distributed to the Speaker of the House of Representatives and the President of the Senate as the Act requires.
The Commission has adopted an altered system of records under the Privacy Act of 1974. The notice includes for this systems of records the name; location; categories of individuals on whom the records are maintained; categories of records in the system; authority for maintenance of the system; each routine use; the policies and practices governing storage, retrievability, access controls, retention and disposal; the title and business address of the agency official responsible for the system of records; procedures for notification, access and contesting the record; and the source for the records in the system. 5 U.S.C. 552(a)(4).
FERC-46 Commission Freedom of Information Act and Privacy Act Request Files
Commission Freedom of Information Act and Privacy Act Request Files.
Unclassified
Federal Energy Regulatory Commission, Office of External Affairs, 888 First Street NE., Washington, DC 20426
All individuals requesting records from FERC under the provisions of the Freedom of Information Act (FOIA) and the Privacy Act (PA) of 1974.
Requester's name and address, request number, description of request, billing information, tracking information, and all correspondence with the requester.
5 U.S.C. 552, 552a; Executive Order 12009.
To record, track and maintain a complete record of events and ensure proper document control of time sensitive responses to FOIA and PA inquiries.
To maintain a tracking system to expedite responses within the statutory time limits for the FOIA requests; to contact FOIA requesters; to prepare an annual report to the U.S. Department of Justice for submission to Congress each fiscal year under section 552(e) of the Freedom of Information Act; to prepare periodic activity reports for the Director, Office of External Affairs, to serve as a point of reference for all events and documents pertinent to the request in case of litigation; and to provide the National Archives and Records Administration, Office of Government Information Services (OGIS) to the extent necessary with information to fulfill its responsibilities in 5 U.S.C. 552(h), to review administrative agency policies, procedures and compliance with FOIA and to facilitate OGIS offering of mediation services to resolve disputes between persons making FOIA requests and administrative agencies.
None.
Records are maintained in electronic and paper format. Electronic records are stored in computerized databases and/or on computer disc. Paper records and records on computer disc are stored in locked file rooms and/or file cabinets.
The records are retrieved by the names of the individual requester, affiliation (where applicable), and subject matter.
Records are maintained in lockable metal file cabinets in a lockable room with a key distributed to those whose official duties require access. Computer data is secured by password. The building is guarded and monitored by security personnel, cameras, ID checks, and other physical security measures.
The retention period is two years after completion date if the information is released or six years after completion date if any or all information is withheld from the requester. Computer records are deleted and paper records are shredded and destroyed.
FOIA Liaison, Office of External Affairs, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
Requests from individuals to determine if a system of records contains information about them should be directed to the System Manager.
Requests for access to records should be directed to the Director, Office of External Affairs, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
Same as notification procedure above.
The subject individual; system manager; FERC staff, and the Director, Office of External Affairs.
None.
Environmental Protection Agency (EPA).
Notice of public advisory committee teleconference.
Pursuant to the Federal Advisory Committee Act, Public Law 92-463, notice is hereby given that the Good Neighbor Environmental Board (Board) will hold a public teleconference on October 14, 2016 from 12:00 p.m.-4:00 p.m. Eastern Daylight Time. For further information regarding the teleconference and background materials, please contact Mark Joyce at the number and email provided below.
The Federal Deposit Insurance Corporation (FDIC), as Receiver for 10002 Miami Valley Bank, Lakeview, Ohio (Receiver) has been authorized to take all actions necessary to terminate the receivership estate of Miami Valley 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 September 1, 2016, 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 10346 San Luis Trust Bank, FSB, San Luis Obispo, CA (Receiver) has been authorized to take all actions necessary to terminate the receivership estate of San Luis Trust Bank, FSB (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 September 1, 2016, 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 10046 TeamBank, N.A., Paola, Kansas (Receiver) has been authorized to take all actions necessary to terminate the receivership estate of TeamBank, N.A (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 September 1, 2016, the Receivership Estate has been terminated, the Receiver discharged, and the Receivership Estate has ceased to exist as a legal entity.
Appraisal Subcommittee of the Federal Financial Institutions Examination Council.
Notice of meeting.
If you plan to attend the ASC Meeting in person, we ask that you send an email to
In accordance with section 10(a)(2) of the Federal Advisory Committee Act (Pub. L. 92-463), the Centers for Disease Control and Prevention (CDC) announces the following meeting for the aforementioned committee:
Please note that the public comment period ends at the time indicated above or following the last call for comments, whichever is earlier. Members of the public who want to comment must sign up by providing their name by mail, email, or telephone, at the addresses provided below by September 23, 2016. Each commenter will be provided up to five minutes for comment. A limited number of time slots are available and will be assigned on a first come-first served basis. Written comments will also be accepted from those unable to attend the public session via an on-line form at the following Web site:
Agenda items are subject to change as priorities dictate.
An agenda is also posted on the NIOSH Web site (
The Director, Management Analysis and Services Office has been delegated the authority to sign
In accordance with section 10(a)(2) of the Federal Advisory Committee Act (Pub. L. 92-463), the Centers for Disease Control and Prevention (CDC), announces the following meeting of the aforementioned committee:
Agenda items are subject to change as priorities dictate.
The Director, Management Analysis and Services Office has been delegated the authority to sign
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing that a proposed collection of information has been submitted to the Office of Management and Budget (OMB) for review and clearance under the Paperwork Reduction Act of 1995.
Fax written comments on the collection of information by October 7, 2016.
To ensure that comments on the information collection are received, OMB recommends that written comments be faxed to the Office of Information and Regulatory Affairs, OMB, Attn: FDA Desk Officer, FAX: 202-395-7285, or emailed to
FDA PRA Staff, Office of Operations, Food and Drug Administration, Three White Flint North 10A-12M, 11601 Landsdown St., North Bethesda, MD 20852,
In compliance with 44 U.S.C. 3507, FDA has submitted the following proposed collection of information to OMB for review and clearance.
A guidance document entitled “Guidance for Administrative Procedures for CLIA Categorization” was released on May 7, 2008. The document describes procedures FDA uses to assign the complexity category to a device. Typically, FDA assigns complexity categorizations to devices at the time of clearance or approval of the device. In this way, no additional burden is incurred by the manufacturer because the labeling (including operating instructions) is included in the premarket notification (510(k)) or premarket approval application (PMA). In some cases, however, a manufacturer may request Clinical Laboratory Improvement Amendments of 1998 (CLIA) categorization even if FDA is not simultaneously reviewing a 510(k) or PMA. One example is when a manufacturer requests that FDA assign CLIA categorization to a previously cleared device that has changed names since the original CLIA categorization. Another example is when a device is exempt from premarket review. In such cases, the guidance recommends that manufacturers provide FDA with a copy of the package insert for the device and a cover letter indicating why the manufacturer is requesting a categorization (
In the
FDA estimates the burden of this collection of information as follows:
The number of respondents is approximately 60. On average, each respondent will request categorizations (independent of a 510(k) or PMA) 15 times per year. The cost, not including personnel, is estimated at $52 per hour (52 × 900), totaling $46,800. This includes the cost of copying and mailing copies of package inserts and a cover letter, which includes a statement of the reason for the request and reference to the original 510(k) numbers, including regulation numbers and product codes. The burden hours are based on FDA familiarity with the types of documentation typically included in a sponsor's categorization requests, and costs for basic office supplies (
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing an opportunity for public comment on the proposed collection of certain information by the Agency. Under the Paperwork Reduction Act of 1995 (the PRA), Federal Agencies are required to publish notice in the
Submit either written or electronic comments on the collection of information by November 7, 2016.
You may submit comments as follows:
Submit electronic comments in the following way:
•
• 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:
•
• 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
FDA PRA Staff, Office of Operations, Food and Drug Administration, Three White Flint North, 11601 Landsdown St., 10A-12M, North Bethesda, MD 20852,
Under the PRA (44 U.S.C. 3501-3520), Federal Agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. “Collection of information” is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c) and includes Agency requests or requirements that members of the public submit reports, keep records, or provide information to a third party. Section 3506(c)(2)(A) of the PRA (44 U.S.C. 3506(c)(2)(A)) requires Federal Agencies to provide a 60-day notice in the
With respect to the following collection of information, FDA invites comments on these topics: (1) Whether the proposed collection of information is necessary for the proper performance of FDA's functions, including whether the information will have practical utility; (2) the accuracy of FDA's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques, when appropriate, and other forms of information technology.
Under section 361 of the Public Health Service Act (the PHS Act) (42 U.S.C. 264), FDA may issue and enforce regulations necessary to prevent the introduction, transmission, or spread of communicable diseases between the States or possessions or from foreign
The regulations in part 1271 (21 CFR part 1271) require domestic and foreign establishments that recover, process, store, label, package, or distribute an HCT/P described in § 1271.10(a), or that perform screening or testing of the cell or tissue donor to register with FDA (§ 1271.10(b)(1)) and submit a list of each HCT/P manufactured (§ 1271.10(b)(2)). Section 1271.21(a) requires an establishment to follow certain procedures for initial registration and listing of HCT/Ps, and § 1271.25(a) and (b) identifies the required initial registration and HCT/P listing information. Section 1271.21(b), in brief, requires an annual update of the establishment registration. Section 1271.21(c)(ii) requires establishments to submit HCT/P listing updates if a change as described in § 1271.25(c) has occurred. Section 1271.25(c) identifies the required HCT/P listing update information. Section 1271.26 requires establishments to submit an amendment if ownership or location of the establishment changes. FDA requires the use of a registration and listing form, Form FDA 3356: Establishment Registration and Listing for Human Cells, Tissues, and Cellular and Tissue-Based Products (HCT/Ps), to submit the required information (§§ 1271.10, 1271.21, 1271.25, and 1271.26). To further facilitate the ease and speed of submissions, electronic submission is accepted at
Form FDA 3356 is being revised as follows: (1) Adding import contact information including an email address and phone number; (2) deleting columns related to HCT/Ps subject to registration and listing under 21 CFR part 207 or 807; and (3) revising the instructions accordingly. The estimated burden is not affected by these changes.
In brief, FDA requires certain HCT/P establishments described in § 1271.1(b) to determine donor eligibility based on donor screening and testing for relevant communicable disease agents and diseases except as provided under § 1271.90. The documented determination of a donor's eligibility is made by a responsible person as defined in § 1271.3(t) and is based on the results of required donor screening, which includes a donor medical history interview (defined in § 1271.3(n)), and testing (§ 1271.50(a)). Certain records must accompany an HCT/P once the donor-eligibility determination has been made (§ 1271.55(a)). This requirement applies both to an HCT/P from a donor who is determined to be eligible as well as to an HCT/P from a donor who is determined to be ineligible or where the donor-eligibility determination is not complete if there is a documented urgent medical need, as defined in § 1271.3(u) (§ 1271.60). Once the donor-eligibility determination has been made, the HCT/P must be accompanied by a summary of records used to make the donor eligibility determination (§ 1271.55(b)), and a statement whether, based on the results of the screening and testing of the donor, the donor is determined to be eligible or ineligible (§ 1271.55(a)(2)). Records used in determining the eligibility of a donor,
When a product is shipped in quarantine, as defined in § 1271.3(q), before completion of screening and testing, the HCT/P must be accompanied by records identifying the donor stating that the donor-eligibility determination has not been completed and stating that the product must not be implanted, transplanted, infused, or transferred until completion of the donor-eligibility determination, except in cases of urgent medical need, as defined in § 1271.3(u) (§ 1271.60(c)). When a HCT/P is used in cases of documented urgent medical need, the results of any completed donor screening and testing, and a list of any required screening and testing that has not yet been completed also must accompany the HCT/P (§ 1271.60(d)(2)). When a HCT/P is used in cases of urgent medical need or from a donor who has been determined to be ineligible (as permitted under § 1271.65), documentation by the HCT/P establishment is required showing that the recipient's physician received notification that the testing and screening were not complete (in cases of urgent medical need), and upon the completion of the donor-eligibility determination, of the results of the determination (§§ 1271.60(d)(3) and (d)(4), and 1271.65(b)(3)).
An HCT/P establishment is also required to establish and maintain procedures for all steps that are performed in determining eligibility (§ 1271.47(a)), including the use of a product from a donor of viable, leukocyte-rich cells or tissue testing reactive for cytomegalovirus (§ 1271.85(b)(2)). The HCT/P establishment must record and justify any departure from a procedure relevant to preventing risks of communicable disease transmission at the time of its occurrence (§ 1271.47(d)).
FDA requires HCT/P establishments to follow CGTP (§ 1271.1(b)). Section 1271.155(a) permits the submission of a request for FDA approval of an exemption from or an alternative to any requirement in subpart C or D of part 1271. Section 1271.290(c) requires establishments to affix a distinct identification code to each HCT/P that they manufacture that relates the HCT/P to the donor and to all records pertaining to the HCT/P. Whenever an establishment distributes an HCT/P to a consignee, § 1271.290(f) requires the establishment to inform the consignee, in writing, of the product tracking requirements and the methods the establishment uses to fulfill these requirements. Non-reproductive HCT/P establishments described in § 1271.10 are required under § 1271.350(a)(1) and (a)(3) to investigate and report to FDA adverse reactions (defined in § 1271.3(y)) using Form FDA 3500A (§ 1271.350(a)(2)). Form FDA 3500A is approved under OMB control number 0910-0291. Section 1271.370(b) and (c) requires establishments to include specific information either on the HCT/P label or with the HCT/P.
The standard operating procedures (SOP) provisions under part 1271 include the following: (1) § 1271.160(b)(2) (receiving, investigation, evaluating, and documenting information relating to core CGTP requirements, including complaints, and for sharing information with consignees and other establishments); (2) § 1271.180(a) (to meet core CGTP requirements for all steps performed in the manufacture of HCT/Ps); (3) § 1271.190(d)(1) (facility cleaning and sanitization); (4) § 1271.200(b) (cleaning, sanitizing, and maintenance of equipment); (5) § 1271.200(c) (calibration of equipment); (6) § 1271.230(a) and (c) (validation of a process and review and evaluation of changes to a validated process); (7) § 1271.250(a) (controls for labeling HCT/Ps); (8) § 1271.265(e) (receipt, predistribution shipment, availability for distribution, and packaging and shipping of HCT/Ps); (9) § 1271.265(f) (suitable for return to inventory); (10) § 1271.270(b) (records management system); (11) § 1271.290(b)(1) (system of HCT/P tracking); and (12) § 1271.320(a) (review, evaluation, and documentation of complaints as defined in § 1271.3(aa)).
Section 1271.155(f) requires an establishment operating under the terms of an exemption or alternative to maintain documentation of FDA's grant of the exemption or approval and the date on which it began operating under the terms of the exemption or alternative. Section 1271.160(b)(3) requires the quality program of an establishment that performs any step in the manufacture of HCT/Ps to document corrective actions relating to core CGTP requirements. Section 1271.160(b)(6) requires documentation of HCT/P deviations. Section 1271.160(d) requires, in brief, documentation of validation of computer software if the establishment relies upon it to comply with core CGTP requirements. Section 1271.190(d)(2) requires documentation of all cleaning and sanitation activities performed to prevent contamination of HCT/Ps. Section 1271.195(d) requires documentation of environmental control and monitoring activities. Section 1271.200(e) requires documentation of all equipment maintenance, cleaning, sanitizing, calibration, and other activities. Section 1271.210(d) requires, in brief, documentation of the receipt, verification, and use of each supply or reagent. Section 1271.230(a) requires documentation of validation activities and results when the results of processing described in § 1271.220 cannot be fully verified by subsequent inspection and tests. Section 1271.230(c) requires that when changes to a validated process subject to § 1271.230(a) occur, documentation of the review and evaluation of the process and revalidation, if necessary, must occur. Section 1271.260(d) and (e) requires documentation of any corrective action taken when proper storage conditions are not met and documentation of the storage temperature for HCT/Ps. Section 1271.265(c)(1) requires documentation that all release criteria have been met before distribution of an HCT/P. Section 1271.265(c)(3) requires documentation of any departure from a procedure relevant to preventing risks of communicable disease transmission at the time of occurrence. Section 1271.265(e) requires documentation of the activities in paragraphs (a) through (d) of this section, which must include identification of the HCT/P and the establishment that supplied the HCT/P, activities performed and the results of each activity, date(s) of activity, quantity of HCT/P subject to the activity, and disposition of the HCT/P. Section 1271.270(a) requires documentation of each step in manufacturing required in part 1271, subparts C and D. Section 1271.270(e) requires documentation of the name and address, and a list of responsibilities of any establishment that performs a manufacturing step for the establishment. Section 1271.290(d) and (e) require documentation of a method for recording the distinct identification code and type of each HCT/P distributed to a consignee to enable tracking from the consignee to the donor and to enable tracking from the donor to the consignee or final disposition. Section 1271.320(b) requires an establishment to maintain a record of each complaint that it receives. The complaint file must contain sufficient information about each complaint for proper review and evaluation of the complaint and for determining whether the complaint is an isolated event or represents a trend.
Respondents to this information collection are establishments that recover, process, store, label, package, or distribute any HCT/P, or perform donor screening or testing. The estimates provided below are based on most recent available information from FDA's database system and trade organizations. The hours per response and hours per record are based on data provided by the Eastern Research Group, or FDA experience with similar recordkeeping or reporting requirements.
There are an estimated 2,218 HCT/P establishments (conventional tissue, eye tissue, peripheral blood stem cell, stem cell products from cord blood, reproductive tissue, and sperm banks), including 667 manufacturers of HCT/P products regulated under the Federal Food, Drug, and Cosmetic Act and section 351 of the PHS Act (42 U.S.C. 262), that have registered and listed with FDA. In addition, we estimate that 182 new establishments have registered with FDA (§§ 1271.10(b)(1) and (b)(2) and 1271.25(a) and (b)). There are an estimated 1,221 listing updates (§§ 1271.10(b)(2), 1271.21(c)(ii), and 1271.25(c)) and 588 location/ownership amendments (§ 1271.26).
Under § 1271.55(a), an estimated total of 2,206,890 HCT/Ps (which include conventional tissues, eye tissues, hematopoetic stem cells/progenitor cells, and reproductive cells and tissues), and an estimated total of 2,066,890 non-reproductive cells and tissues (total HCT/Ps minus reproductive cells and tissues) are distributed per year by an estimated 1,551 establishments (2,218−667 = 1,551) with approved applications).
Under § 1271.60(c) and (d)(2), FDA estimates that 1,375 establishments shipped an estimated 572,000 HCT/P under quarantine, and that an estimated 25 establishments requested 78 exemptions from or alternative to any requirement under part 1271, subpart C or D, specifically under § 1271.155(a).
Under §§ 1271.290(c) and 1271.370(b) and (c), the estimated 1,561 non-reproductive HCT/P establishments label each of their 2,066,890 HCT/Ps with certain information. These establishments are also required to inform their consignees in writing of the requirements for tracking and of their established tracking system under § 1271.290(f).
FDA estimates 34 HCT/P establishments submitted 166 adverse reaction reports with 136 involving a communicable disease (§ 1271.350(a)(1)).
FDA estimates that 182 new establishments will create SOPs, and that 2,218 establishments will review and revise existing SOPs annually.
FDA estimates that 1,109 HCT/P establishments (2,218 × 50 percent = 1,109) and 781 non-reproductive HCT/P establishments (1,561 × 50 percent = 781) record and justify a departure from the procedures (§§ 1271.47(d) and 1271.265(c)(3)).
Under § 1271.50(a), HCT/P establishments are required to have a documented medical history interview about the donor's medical history and relevant social behavior as part of the
FDA estimates that 665 HCT/P establishments (2,218 × 30 percent = 665) document an urgent medical need of the product to notify the physician using the HCT/P (§§ 1271.60(d)(3) and 1271.65(b)(3)).
FDA also estimates that 1,774 HCT/P establishments (2,218 × 80 percent = 1,774) have to maintain records for an average of 2 contract establishments to perform their manufacturing process (§ 1271.270(e), and 1,249 HCT/P establishments (1,561 × 80 percent = 1,249) maintain an average of 5 complaint records annually (§ 1271.320(b)).
In some cases, the estimated burden may appear to be lower or higher than the burden experienced by individual establishments. The estimated burden in these charts is an estimated average burden, taking into account the range of impact each regulation may have.
FDA estimates the burden of this collection of information as follows:
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing the issuance of an Emergency Use Authorization (EUA) (the Authorization) for an in vitro diagnostic device for detection of the Zika virus in response to the Zika virus outbreak in the Americas. FDA issued this Authorization under the Federal Food, Drug, and Cosmetic Act (the FD&C Act) as requested by Viracor-IBT Laboratories, Inc. The Authorization contains, among other things, conditions on the emergency use of the authorized in vitro diagnostic device. The Authorization follows the February 26, 2016, determination by the Secretary of Health and Human Services (HHS) that there is a significant potential for a public health emergency that has a significant potential to affect national security or the health and security of U.S. citizens living abroad and that involves Zika virus. On the basis of such determination, the Secretary of HHS declared on February 26, 2016, that circumstances exist justifying the authorization of emergency use of in vitro diagnostic tests for detection of Zika virus and/or diagnosis of Zika virus infection, subject to the terms of any authorization issued under the FD&C Act. The Authorization, which includes an explanation of the reasons for issuance, is reprinted in this document.
The Authorization is effective as of July 19, 2016.
Submit written requests for single copies of the EUA to the Office of Counterterrorism and Emerging Threats, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 1, Rm. 4338, Silver Spring, MD 20993-0002. Send one self-addressed adhesive label to assist that office in processing your request or include a fax number to which the Authorization may be sent. See the
Carmen Maher, Office of Counterterrorism and Emerging Threats, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 1, Rm. 4347, Silver Spring, MD 20993-0002, 301-796-8510 (this is not a toll free number).
Section 564 of the FD&C Act (21 U.S.C. 360bbb-3) as amended by the Project BioShield Act of 2004 (Pub. L. 108-276) and the Pandemic and All-Hazards Preparedness Reauthorization Act of 2013 (Pub. L. 113-5) allows FDA to strengthen the public health protections against biological, chemical, nuclear, and radiological agents. Among other things, section 564 of the FD&C Act allows FDA to authorize the use of an unapproved medical product or an unapproved use of an approved medical product in certain situations. With this EUA authority, FDA can help assure that medical countermeasures may be used in emergencies to diagnose, treat, or prevent serious or life-threatening diseases or conditions caused by biological, chemical, nuclear, or radiological agents when there are no adequate, approved, and available alternatives.
Section 564(b)(1) of the FD&C Act provides that, before an EUA may be issued, the Secretary of HHS must declare that circumstances exist justifying the authorization based on one of the following grounds: (1) A determination by the Secretary of Homeland Security that there is a domestic emergency, or a significant potential for a domestic emergency, involving a heightened risk of attack with a biological, chemical, radiological, or nuclear agent or agents; (2) a determination by the Secretary of Defense that there is a military emergency, or a significant potential for a military emergency, involving a heightened risk to U.S. military forces of attack with a biological, chemical, radiological, or nuclear agent or agents; (3) a determination by the Secretary of HHS that there is a public health emergency, or a significant potential for a public health emergency, that affects, or has a significant potential to affect, national security or the health and security of U.S. citizens living abroad, and that involves a biological, chemical, radiological, or nuclear agent or agents, or a disease or condition that may be attributable to such agent or agents; or (4) the identification of a material threat by the Secretary of Homeland Security under section 319F-2 of the Public Health Service (PHS) Act (42 U.S.C. 247d-6b) sufficient to affect national security or the health and security of U.S. citizens living abroad.
Once the Secretary of HHS has declared that circumstances exist justifying an authorization under section 564 of the FD&C Act, FDA may authorize the emergency use of a drug, device, or biological product if the Agency concludes that the statutory criteria are satisfied. Under section 564(h)(1) of the FD&C Act, FDA is required to publish in the
No other criteria for issuance have been prescribed by regulation under section 564(c)(4) of the FD&C Act. Because the statute is self-executing, regulations or guidance are not required for FDA to implement the EUA authority.
II. EUA Request for an In Vitro Diagnostic Device for Detection of the Zika Virus
On February 26, 2016, the Secretary of HHS determined that there is a significant potential for a public health emergency that has a significant potential to affect national security or the health and security of U.S. citizens living abroad and that involves Zika virus. On February 26, 2016, under section 564(b)(1) of the FD&C Act, and on the basis of such determination, the Secretary of HHS declared that circumstances exist justifying the authorization of emergency use of in vitro diagnostic tests for detection of Zika virus and/or diagnosis of Zika virus infection, subject to the terms of any authorization issued under section 564 of the FD&C Act. Notice of the determination and declaration of the Secretary was published in the
An electronic version of this document and the full text of the Authorization are available on the Internet at
Having concluded that the criteria for issuance of the Authorization under section 564(c) of the FD&C Act are met, FDA has authorized the emergency use of an in vitro diagnostic device for detection of Zika virus subject to the terms of the Authorization. The Authorization in its entirety (not including the authorized versions of the fact sheets and other written materials) follows and provides an explanation of the reasons for its issuance, as required by section 564(h)(1) of the FD&C Act:
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA or we) is requesting comments related to the regulatory status of vinpocetine. Specifically, we request comments on our tentative conclusion that vinpocetine is not a dietary ingredient and is excluded from the definition of dietary supplement in the Federal Food, Drug, and Cosmetic Act (FD&C Act). This action is being taken as part of an administrative proceeding to determine the regulatory status of vinpocetine. All comments submitted by the comment deadline (see
Submit either electronic or written comments on the notice by November 7, 2016.
You may submit comments as follows:
Submit electronic comments in the following way:
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• 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:
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• 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
Cara Welch, Center for Food Safety and Applied Nutrition (HFS-810), Food and Drug Administration, 5001 Campus Dr., College Park, MD 20740, 240-402-2333.
We are initiating an administrative proceeding under 21 CFR 10.25(b) to determine the regulatory status of vinpocetine (chemical name: Ethyl apovincaminate). Specifically, we are trying to determine: (1) Whether vinpocetine is a dietary ingredient within the meaning of the FD&C Act and (2) whether it is excluded from being a dietary supplement under the FD&C Act.
Under section 201(ff)(1) of the FD&C Act (21 U.S.C. 321(ff)(1)), the term “dietary supplement” is defined in part as a product (other than tobacco) intended to supplement the diet that bears or contains one or more of the following dietary ingredients: (A) A vitamin; (B) a mineral; (C) an herb or other botanical; (D) an amino acid; (E) a dietary substance for use by man to supplement the diet by increasing the total dietary intake; or (F) a concentrate, metabolite, constituent, extract, or combination of any ingredient described in clause (A), (B), (C), (D), or (E).
Additionally, under section 201(ff)(3)(B)(ii) of the FD&C Act, a dietary supplement cannot include “an article authorized for investigation as a new drug . . . for which substantial clinical investigations have been instituted and for which the existence of such investigations has been made public” unless the article was marketed as a dietary supplement or as a food before such authorization.
Recently, questions have been raised as to whether vinpocetine is a dietary ingredient and is excluded from the definition of dietary supplement under sections 201(ff)(1) and (3) of the FD&C Act, respectively.
According to records on file in FDA's Center for Drug Evaluation and Research, vinpocetine was authorized for investigation as a new drug in 1981.
On July 8, 1997, a new dietary ingredient notification
We first consider whether vinpocetine is a dietary ingredient under section 201(ff)(1) of the FD&C Act—specifically, whether it is a vitamin, mineral, herb or other botanical, amino acid, dietary substance for use by man to supplement the diet by increasing the total dietary intake, or a concentrate, metabolite, constituent, extract, or combination of dietary ingredients from the preceding categories. We are not aware of any argument that vinpocetine is a vitamin, a mineral, or an amino acid. Thus, vinpocetine does not appear to qualify as a dietary ingredient under section 201(ff)(1)(A), (B), or (D) of the FD&C Act.
Vinpocetine is not an herb or other botanical, nor is it a constituent of any botanical. Rather, vinpocetine is a synthetic compound, derived from vincamine, an alkaloid found in the
Vinpocetine is not a dietary substance for use by man to supplement the diet by increasing the total dietary intake. Extensive database and literature searches did not identify any food use of vinpocetine. Thus, vinpocetine does not appear to qualify as a dietary ingredient under section 201(ff)(1)(E) of the FD&C Act.
Finally, vinpocetine is not a concentrate, metabolite, constituent, extract, or combination of any ingredient described in section 201(ff)(1)(A), (B), (C), (D), or (E) of the FD&C Act. We are not aware of any factual basis to conclude that vinpocetine is a concentrate, metabolite, constituent, extract, or combination of a vitamin, mineral, amino acid, or dietary substance. As described earlier, vinpocetine is not found in
We therefore tentatively conclude that vinpocetine is not a dietary ingredient under section 201(ff)(1) of the FD&C Act because it does not fit any of the dietary ingredient categories.
As noted above, the statutory definition of “dietary supplement” excludes an article authorized for investigation as a new drug for which substantial clinical investigations have been instituted and made public, unless the article was marketed as a dietary supplement or as a food before such authorization (see section 201(ff)(3)(B)(ii) of the FD&C Act).
Based on FDA's IND records and articles published between 1985 and 1988 that mention or report on phase 3 clinical trials for vinpocetine (Refs. 1 to 4), it appears that: (1) Vinpocetine was authorized for investigation as a new drug in 1981, long before the first new dietary ingredient notification for vinpocetine was filed in 1997 and, therefore, also long before vinpocetine was marketed as a dietary supplement; (2) substantial clinical investigations of vinpocetine have been instituted, and (3) the existence of such investigations has been made public.
We therefore tentatively conclude that vinpocetine is excluded from the dietary supplement definition under section 201(ff)(3)(B) of the FD&C Act.
Based on the evidence available to us to date, we tentatively conclude that vinpocetine is not a dietary ingredient as defined in section 201(ff)(1) of the FD&C Act. We further tentatively conclude that vinpocetine is excluded from the dietary supplement definition under section 201(ff)(3)(B) of the FD&C Act and therefore may not be marketed as or in a dietary supplement. We are interested in receiving information that would inform our final decision on the regulatory status of vinpocetine, such as information about any food uses of vinpocetine and information on the date vinpocetine was first marketed as a food or as a dietary supplement.
To afford all interested parties an adequate opportunity to participate in this matter, we request comments and other supporting information related to this matter. Interested persons may submit to the Division of Dockets Management (see
The following references are on display in FDA's Division of Dockets Management (see
4. The Pink Sheet, “American Home Products' ‘Third Generation’ TPA Entering Clinicals,” March 21, 1988. Retrieved from:
Office of the Secretary, HHS.
Notice.
In compliance with section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Office of the Secretary (OS), Department of Health and Human Services, announces plans to submit a new Information Collection Request (ICR), described below, to the Office of Management and Budget (OMB). Prior to submitting the ICR to OMB, OS seeks comments from the public regarding the burden estimate below or any other aspect of the ICR. Prior to submitting the ICR to OMB, OS seeks comments from the public regarding the burden estimate, below, or any other aspect of the ICR.
Comments on the ICR must be received on or before [November 7, 2016].
Submit your comments to
Information Collection Clearance staff,
When submitting comments or requesting information, please include the document identifier HHS-OS-0990-new-60D for reference.
OS specifically requests comments on (1) the necessity and utility of the proposed information collection for the proper performance of the agency's functions, (2) the accuracy of the estimated burden, (3) ways to enhance the quality, utility, and clarity of the information to be collected, and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
Indian Health Service, Department of Health and Human Services.
Notice and request for comments.
Indian Health Service (IHS) has entered into a contract with the National Academy of Public Administration (the Academy) to assist in the development of a five-year strategic plan. Funding for this project was provided by Congress in the 2016 Consolidated Appropriations Act, which directs IHS to develop the plan in consultation with urban Indians and the Academy.
As part of this project, the Academy project team is in the process of conducting extensive outreach to IHS/Office of Urban Indian Health Programs (OUIHP) leadership and employees, as well as conferring with urban Indian organizations and other key external stakeholder groups. The final product will be a strategic plan to guide the work of the headquarters office of OUIHP, area urban coordinators, and urban Indian organizations participating in IHS programs. The strategic plan will be completed by the end of December 2016.
IHS is requesting input on the strategic planning process, the strengths and weaknesses of OUIHP, and the opportunities and threats facing the program. Comments will be used to help develop the mission, goals, objectives, and strategies to be included in the strategic plan.
Submit your input to the Academy no later than September 16, 2016. All comments submitted to the Academy are not for attribution.
Pamela Haze, Project Director, National Academy of Public Administration, 1600 K St. NW., Suite 400, Washington, DC 20006, (201) 204-3682.
National Institutes of Health, HHS.
Notice.
This notice, in accordance with 35 U.S.C. 209 and 37 CFR part 404, that the National Institutes of Health, Department of Health and Human Services, is contemplating the grant of an exclusive patent license to practice the inventions embodied in the following Patents and Patent Applications and all continuing U.S. and foreign patents/patent applications to Sangamo BioSciences, Inc. located in Richmond, California, USA:
U.S. Provisional Patent Application 62/006,313, filed 2 June 2014 and entitled “Chimeric Antigen Receptors Targeting CD-19” [HHS Ref. E-042-2014/0-US-01]; and PCT Patent Application PCT/US2015/033473, filed 1 June 2015 and entitled “Chimeric Antigen Receptors Targeting CD-19” [HHS Ref. E-042-2014/0-PCT-02].
The patent rights in these inventions have been assigned and/or exclusively licensed to the Government of the United States of America.
The prospective exclusive license territory may be worldwide and the field of use may be limited to the use of Licensed Patent Rights for the following: “The integration of a monospecific anti-CD19 chimeric antigen receptor (CAR) into genome-edited, allogeneic T cells (where the donor and recipient are different), where the monospecific CAR has at least: (a) The complementary determining region (CDR) sequences of the anti-CD19 47G4 antibody; and (b) a T cell signaling domain, for the prophylaxis and treatment of CD19-positive malignancies.”
Only written comments and/or applications for a license which are received by the NIH Office of Technology Transfer on or before September 22, 2016 will be considered.
Requests for copies of the patent application, inquiries, comments, and other materials relating to the contemplated exclusive license should be directed to: David A. Lambertson, Ph.D., Senior Licensing and Patenting Manager, National Cancer Institute, 9609 Medical Center Drive, Rm. 1-E530 MSC9702, Rockville, MD 20850-9702, Email:
This invention concerns an anti-CD19 chimeric antigen receptor (CAR) and methods of using the CAR for the treatment of CD19-expressing cancers, including B cell malignancies. With regard to the proposed license, the CAR covered by the invention will be integrated into a genome-edited allogeneic (where the donor and recipient of the T cell are different individuals) T cell, and the resulting anti-CD19 CAR-expressing genome-edited allogeneic T cell will be introduced into a cancer patient to exhibit a therapeutic effect. CD19 is a cell surface antigen that is preferentially expressed on certain types of cancer cells, particularly cancers of B cell origin such as Non-Hodgkin's Leukemia (NHL), acute lymphoblastic leukemia (ALL) and chronic lymphocytic leukemia (CLL). The anti-CD19 CARs of this technology contain (1) antigen recognition sequences that bind specifically to CD19 and (2) signaling domains that can activate the cytotoxic functions of a T cell. The anti-CD19 CAR can be integrated into genome-edited allogeneic T cells; from there, genome-edited allogeneic T cells expressing the anti-CD19 CAR are selected, expanded and then introduced into a patient. Once the anti-CD19 CAR-expressing genome-edited allogeneic T cells are introduced into the patient, the T cells can selectively bind to CD19-expressing cancer cells through its antigen recognition sequences, thereby activating the T cell through its signaling domains to selectively kill the cancer cells. Through this mechanism of action, the selectivity of the a CAR allows the T cells to kill cancer cells while leaving healthy, essential cells unharmed. This can result in an effective therapeutic strategy with fewer side effects due to less non-specific killing of cells.
The prospective exclusive license will be royalty bearing and will comply with the terms and conditions of 35 U.S.C. 209 and 37 CFR part 404.7. The prospective exclusive license may be granted unless within fifteen (15) days from the date of this published notice, the NIH receives written evidence and argument that establishes that the grant of the license would not be consistent with the requirements of 35 U.S.C. 209 and 37 CFR part 404.7.
Complete applications for a license in the prospective field of use that are filed in response to this notice will be treated as objections to the grant of the contemplated Exclusive Patent License Agreement. Comments and objections submitted to this notice will not be made available for public inspection and, to the extent permitted by law, will not be released under the
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.
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 meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), title 5 U.S.C., as amended. The contract proposals and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the contract proposals, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
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.
In compliance with Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995 concerning opportunity for public comment on proposed collections of information, the Substance Abuse and Mental Health Services Administration (SAMHSA) will publish periodic summaries of proposed projects. To request more information on the proposed projects or to obtain a copy of the information collection plans, call the SAMHSA Reports Clearance Officer on (240) 276-1243.
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 shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the proposed collection of information; (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 respondents, including through the use of automated collection techniques or other forms of information technology.
The Substance Abuse and Mental Health Services Administration (SAMHSA) is requesting an approval from the Office of Management and Budget (OMB) for an amendment to the FY 2016-2017 Uniform Application, Section III. Behavioral Health Assessment and Plan, C. Environmental Factors and Plan. The intent of this amendment is to gather information regarding the states' and jurisdictions' plans to implement elements of a syringe services program at 1 or more community-based organizations that receive amounts from the grant to provide substance use disorder treatment and recovery services to persons who inject drugs. In response to the emergence of prescription drug and heroin overdoses and associated deaths in many states and jurisdictions, SAMHSA issued guidance on April 2, 2014, to the states and jurisdictions regarding the use of SABG funds for prevention education and training regarding overdoses and the purchase of naloxone (Narcan®) and related materials to assemble overdose prevention kits.
Respondents are the 50 states and the jurisdictions (District of Columbia, the Commonwealth of Puerto Rico, the U.S. Virgin Islands, American Samoa, Commonwealth of Northern Mariana Islands, Federated States of Micronesia, Guam, Republic of Marshall Islands, Republic of Palau, and the Red Lake Band of Chippewa Indians of Minnesota).
The following reporting burden is based on estimates developed considering the State substance abuse and mental health authorities responsible for these activities and represents the average total hours to assemble, format, and produce the requested information.
Link for the application:
Send comments to Summer King, SAMHSA Reports Clearance Officer, 5600 Fishers Lane, Room 15E57-B, Rockville, Maryland 20857,
Coast Guard, Department of Homeland Security.
Notice of Federal Advisory Committee meeting.
The Commercial Fishing Safety Advisory Committee will meet in Savannah, Georgia to discuss various issues relating to safety in the commercial fishing industry. This meeting will be open to the public.
The Committee will meet on Tuesday, September 27, Wednesday September 28, and Thursday September 29, 2016 from 8 a.m. to 5:30 p.m. However, on Tuesday September 27 from 8 a.m. to 10 a.m., administrative items and issues will be discussed with Committee members only. The public meeting will commence at 10 a.m. The meeting may close early if all business is finished.
The Committee will meet at the United States Federal Building located at 124 Barnard Street, Savannah, Georgia, 31401 in Conference Room #1.
If you are planning to attend the meeting, you will be required to pass through a security checkpoint. You will be required to show valid government
For information on facilities or services for individuals with disabilities or to request special assistance at the meeting, contact the person listed in the
Public oral comment periods will be held during the meeting after each presentation and at the end of each day. Speakers are requested to limit their comments to 3 minutes. Please note that the public oral comment periods may end before the prescribed ending time following the last call for comments. Contact Mr. Jack Kemerer as indicated below to register as a speaker.
Mr. Jack Kemerer, Alternate Designated Federal Officer for the Commercial Fishing Safety Advisory Committee, Commandant (CG-CVC-3), United States Coast Guard Headquarters, 2703 Martin Luther King Junior Avenue, South East, Mail Stop 7501, Washington, DC 20593-7501; telephone 202-372-1249, facsimile 202-372-8385, electronic mail:
Notice of this meeting is in compliance with the Federal Advisory Committee Act, Title 5 U.S.C., Appendix.
The Commercial Fishing Safety Advisory Committee is authorized by Title 46 United States Code Section 4508. The Committee's purpose is to provide advice and recommendations to the United States Coast Guard and the Department of Homeland Security on matters relating to the safe operation of commercial fishing industry vessels.
A copy of available meeting documentation will be posted to the docket, as noted above, and at
The Commercial Fishing Safety Advisory Committee will meet to review, discuss and formulate recommendations on topics contained in the agenda.
The meeting will include administrative matters, reports, presentations, discussions, as follows:
(1) 8 a.m. to 10 a.m. Committee Members Only. Federal Advisory Committee Act administrative matters to include Commercial Fishing Safety Committee member training.
(2) 10 a.m. Open to the Public. Introductions, swearing-in of new members, election of Chair and Vice-Chair.
(3) Status of Commercial Fishing Vessel Safety Rulemaking projects resulting from requirements set forth in the Coast Guard Authorization Act of 2010 and the Coast Guard and Maritime Transportation Act of 2012.
(4) Coast Guard District Commercial Fishing Vessel Safety Coordinator reports on activities and initiatives.
(5) Updates on safety and survival equipment developments by Committee member and any industry representatives present.
(6) Presentation and discussion on casualties, by regions and fisheries, and an update on safety and risk-reduction-related projects by the National Institute for Occupational Safety and Health.
(7) Presentation and discussion on E-charts, Automatic Identification Systems, and Digital Selective Calling by the United States Coast Guard Navigation Office.
(8) Public Comment Period.
(9) Adjournment of meeting.
The meeting will include a review and discussion of the United States Coast Guard Notice of Proposed Rulemaking (46 CFR part 28, Commercial Fishing Vessels—Implementation of 2010 and 2012 Legislation) published in the
(1) Development of an Enhanced Oversight Program as outlined in Coast Guard Marine Safety Information Bulletin 11-16 dated July 20, 2016.
(2) Development of guidance to ensure compliance with construction standards for vessels 50-79 feet under Title 46 U.S.C section 4503(c)(2).
(3) Goals and objectives for operator competency training as set forth in Title 46 United States Code section 4502.
(4) Status Reports from Subcommittee Chairs to full Committee.
(5) Public Comment Period.
(6) Adjournment of meeting.
The meeting will include Subcommittee/working group discussions, reports and recommendations as follows:
(1) Subcommittee/working groups meet.
(2) Subcommittee/working groups report to full Committee and make recommendations.
(3) There will be a comment period for Commercial Fishing Safety Advisory Committee members and a comment period for the public after each report and discussion. The Committee will review the information presented on any issues, deliberate on any recommendations presented in Subcommittee reports, and formulate recommendations for the Department's consideration.
(4) Future plans and goals for the Committee.
(5) Next Committee meeting, plans and recommended location.
(6) Comments on the meeting from Committee members.
(7) Adjournment of meeting.
Federal Emergency Management Agency, DHS.
Committee Management; notice of rescheduled Federal Advisory Committee meeting.
The Federal Emergency Management Agency (FEMA) Technical Mapping Advisory Council (TMAC) teleconference meeting scheduled for September 13 and 14, 2016 is rescheduled for September 23 and 26, 2016. FEMA previously published a notice announcing this meeting in the
The rescheduled TMAC meeting will be held on Friday, September 23, 2016, from 10:00 a.m. to 5:00 p.m. Eastern Daylight Time (EDT) and on Monday, September 26 from 10:00 a.m. to 5:00 p.m. Eastern Daylight Time (EDT).
The rescheduled TMAC meeting will be held via conference call.
Written comments concerning this rescheduled TMAC meeting may be submitted by one of the following methods and should be identified by Docket ID FEMA-2014-0022.
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Kathleen Boyer, Designated Federal Officer for the TMAC, FEMA, 500 C St SW., Washington, DC 20024, telephone (202) 646-4023, and email
Federal Emergency Management Agency, DHS.
Notice.
This notice amends the notice of a major disaster declaration for State of West Virginia (FEMA-4273-DR), dated June 25, 2016, and related determinations.
August 26, 2016.
Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW., Washington, DC 20472, (202) 646-2833.
The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, William C. Watrel, of FEMA is appointed to act as the Federal Coordinating Officer for this disaster.
This action terminates the appointment of Albert Lewis as Federal Coordinating Officer for this disaster.
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.
Office of the Chief Information Officer, HUD.
Notice.
HUD has submitted the proposed information collection requirement described below to the Office of Management and Budget (OMB) for review, in accordance with the Paperwork Reduction Act. The purpose of this notice is to allow for an additional 30 days of public comment.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB Control Number and should be sent to: HUD Desk Officer, Office of Management and Budget, New Executive Office Building, Washington, DC 20503; fax: 202-395-5806. Email:
Colette Pollard, Reports Management Officer, QMAC, Department of Housing and Urban Development, 451 7th Street SW., Washington, DC 20410; email Colette Pollard at
Copies of available documents submitted to OMB may be obtained from Ms. Pollard.
This notice informs the public that HUD is seeking approval from OMB for the information collection described in Section A.
The
This notice is soliciting comments from members of the public and affected parties concerning the collection of information described in Section A on the following:
(1) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
(2) The accuracy of the agency's estimate of the burden of the proposed collection of information;
(3) Ways to enhance the quality, utility, and clarity of the information to be collected; and
(4) Ways to minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology,
Section 3507 of the Paperwork Reduction Act of 1995, 44 U.S.C. Chapter 35.
Office of the Assistant Secretary for Housing—Federal Housing Commissioner, HUD.
Notice; solicitation of comment.
The Section 203(k) Program is HUD's primary program for the rehabilitation and repair of single family properties. The Section 203(k) mortgage program enables homebuyers and homeowners to finance the purchase, or refinance of a home and include the rehabilitation costs through a single mortgage. There are two types of 203(k) rehabilitation mortgages: Standard 203(k) and Limited 203(k).
The Standard 203(k) mortgage may be used for remodeling, rehabilitation and repairs that may have structural components, involve more complex work and the total rehabilitation costs must be greater than $5,000. The Limited 203(k) mortgage may only be used for minor remodeling and non-structural repairs. The total rehabilitation cost may not exceed $35,000 and there is no minimum cost.
As part of the Section 203(k) program requirements, the Federal Housing Administration (FHA) maintains a list of approved 203(k) Consultants on the FHA 203(k) Consultant Roster in FHA Connection. An FHA-approved 203(k) Consultant is required for all Standard 203(k) mortgages. A 203(k) Consultant is not required under the Limited 203(k) program, but may be used. FHA-approved 203(k) Consultants are required to perform responsibilities during the processing and rehabilitation phase of the 203(k) program. FHA-approved 203(k) Consultants who are placed on FHA's 203(k) Consultant Roster are deemed qualified to complete these duties and therefore permitted to collect a fee for this service. In 1995, HUD issued its current Section 203(k) Consultant Fee Schedule and now seeks to update the Section 203(k) Fee Schedule to align with similarly performed services and the corresponding fees collected for such services. As a result, this notice seeks public comment on revising the current structure of the fee and the maximum amount of fees a 203(k) Consultant would be permitted to charge on a Section 203(k) mortgage.
Interested persons are invited to submit comments regarding this notice to the Regulations Division, Office of General Counsel, Department of Housing and Urban Development, 451 7th Street SW., Room 10276, Washington, DC 20410-0500.
Communications must refer to the above docket number and title. There are two methods for submitting public comments. All submissions must refer to the above docket number and title.
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To receive consideration as public comments, comments must be submitted through one of the two methods specified above. Again, all submissions must refer to the docket number and title of the notice.
Kevin L. Stevens, Director, Home Mortgage Insurance Division, Office of Single Family Program Development, Office of Housing, Department of Housing and Urban Development, 451 7th Street SW., Room 9266, Washington, DC 20410-9000, telephone number 202-402-4137 (this is not a toll-free number). Persons with hearing or speech impairments may access this number by calling the Federal Relay Service at 800-877-8339 (this is a toll-free number).
Section 203(k) of the National Housing Act (12 U.S.C. 1709(k)) authorizes HUD to insure a purchase or a refinance mortgage on an existing 1-4 unit single family structure and include the rehabilitation costs through a single mortgage. The Section 203(k) Program is HUD's primary program for the rehabilitation and repair of single family properties. The Section 203(k) program is important for neighborhood revitalization and homeownership opportunities. The regulations implementing the Section 203(k) Program are codified at 24 CFR 203.50.
The Section 203(k) Program fills a unique and important role for homebuyers. In the conventional loan market, a homebuyer who purchases a home that is in need of repair or modernization usually has to follow a complicated and costly process. The homebuyer must obtain financing to purchase the dwelling, additional financing for the rehabilitation work, and a permanent mortgage after rehabilitation is completed to pay off the interim loans. The interim acquisition and improvement loans often have relatively high interest rates and short repayment terms. The Section 203(k) Program addresses this by permitting a homebuyer to obtain a single loan, at a long-term fixed or variable rate, to finance both the acquisition and rehabilitation of the property.
There are two types of 203(k) rehabilitation mortgages: Standard 203(k) and Limited 203(k). The Standard 203(k) mortgage may be used for remodeling, rehabilitation and repairs that may have structural components involve complex work and must have a total rehabilitation costs greater than $5,000. The Limited 203(k) mortgage may only be used for minor remodeling and non-structural repairs, the total rehabilitation cost may not exceed $35,000 and there is no minimum rehabilitation cost.
The extent of the rehabilitation covered by the Section 203(k) mortgage may range from relatively minor to virtual reconstruction. For example, a home that will be demolished as part of rehabilitation is eligible, provided that the existing foundation remains in place. In addition to typical home rehabilitation projects, the Section 203(k) Program can be used to convert a property of any size to a one- to four-unit dwelling. Section 203(k) mortgage insurance can also be used to augment Energy Efficient Mortgages, Section 203(h) Mortgage Insurance for Victims of a Presidentially-Declared Major Disaster Area, and Mortgage Insurance for Solar and Wind Technologies. All improvements, renovations, or repairs undertaken with Section 203(k) mortgage insurance must comply with the HUD Minimum Property Requirements, HUD Minimum Property Standards and all local codes and ordinances.
An FHA-approved 203(k) Consultant is required for all Standard 203(k) mortgages and may be used for Limited 203(k) mortgages. As part of the Section 203(k) program requirements, the Federal Housing Administration (FHA) maintains a list of approved 203(k) Consultants on the FHA 203(k) Consultant Roster from which the Mortgagee must select a 203(k) Consultant and assign the 203(k) Consultant to the transaction, if required.
When a Section 203(k) Consultant is required, the Consultant will enter into a written agreement with the Borrower that outlines the services that the Consultant will perform. In some cases, the Mortgagee or Borrower may require the Consultant to conduct a Feasibility Study to determine if the 203(k) mortgage is achievable, based on the costs of the rehabilitation project. The 203(k) Consultant conducts a Feasibility Study by completing a preliminary inspection of the property, and estimates the material and labor costs for the project.
The 203(k) Consultant must inspect the property to ensure:
• There are no rodents, dry rot, termites and other infestation the property;
• there are no defects that will affect the health and safety of the occupants;
• there exists adequate structural, heating, plumbing, electrical and roofing systems; and
• there are upgrades to the structure's thermal proportion (when necessary).
The Consultant must prepare a report on the current condition of the property that categorically examines the structure utilizing a 35 point checklist. The Consultant must determine the repairs/improvements that are required to meet the U.S. Department of Housing and Urban Development (HUD's) Minimum Property Requirements, Minimum Property Standards and local requirements. The report must address any deficiencies that exist. The Consultant is responsible for identifying all required architectural exhibits. The Consultant must prepare the exhibits, or, if not qualified to prepare all of the necessary exhibits, must obtain the exhibits from a qualified subcontractor.
The Consultant must prepare an unbiased Work Write-up and Cost Estimate without using a contractor's estimate. The Work Write-Up and Cost Estimate must be detailed as to the work being performed based on the project proposal, including all required reports.
The Consultant must physically inspect the work for completion, quality of workmanship, conformity to local codes and ordinances, and ensure that all building permits are onsite for the work that was performed at each draw request.
At the Borrower's or Mortgagee's request, the Consultant must review proposed changes to the Work Write-Up and prepare a Change Order Form HUD-95277. The Consultant must inform the Mortgagee of the progress of the rehabilitation and of any problems that arise, including:
• Work stoppages for more than 30 consecutive days or work not progressing;
• significant deviations from the Work Write-Up without the Consultant's approval;
• any issues that could affect adherence to the program requirements or property eligibility; or
• any issues that could affect the health and safety of the occupants or the security of the structure.
The Borrower is responsible for the fee charged by the Section 203(k) Consultant. Under the Standard 203(k) program, the Consultant fee charged for
Under the existing structure, the fee is based on a range of repair costs, recognizing that more extensive repairs would require more time and are costlier for the Consultant to complete. It also allows for some level of change over time as repair costs increase. HUD establishes and monitors the maximum fees that a Section 203(k) Consultant may charge a Borrower to prepare the Work Write-Up for repairs associated with the Section 203(k) mortgage. The Work Write-Up includes the initial inspection, Architectural Exhibit Review and Cost Estimate. The current fee schedule, which HUD issued in 1995, is as follows:
The 203(k) Roster Consultant may also charge a reasonable and customary fee, not to exceed $350 for each draw inspection request plus mileage at the current Internal Revenue Service mileage rate when the place of business is more than 15 miles from the property.
HUD has determined that the existing fee structure may discourage Consultant participation in the Section 203(k) Program and has the potential to limit access to credit. Between 2012 and 2015, the volume of loans requiring the use of a Consultant fell from 6,753 to 5,359. Based on the first two quarters of 2016, the projected volume of loans requiring the use of a Consultant is 5,132, while the projected volume of loans not requiring the use of a Consultant is 14,224. This data suggests that Borrowers are choosing the less complicated repair work, not requiring a Consultant. HUD believes that establishing a fee structure that is more in alignment with market rates would increase Consultants' participation in the Section 203(k) program and expand access to credit by encouraging and enabling more Borrowers to purchase properties that require substantial rehabilitation. The willingness and ability of Borrowers to purchase properties involving substantial rehabilitation would contribute to the reduction in build-up of HUD's Real Estate Owned inventories, result in an increase in energy efficient homes and assist in the stabilization of the housing market.
As part of its policy consolidation effort, HUD posted on the Single Family Housing Policy Drafting Table
In order to better inform HUD, this notice seeks public comment on ways to revise the fee schedule for 203(k) Consultants. HUD is specifically seeking information to determine whether Consultant fees should continue to be based on the total cost of repairs or on some other metric. While all comments on updating the Consultant fee schedule are welcome, HUD is soliciting specific comments on the following options:
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Office of the Chief Information Officer, HUD.
Notice.
HUD has submitted the proposed information collection requirement described below to the Office of Management and Budget (OMB) for review, in accordance with the Paperwork Reduction Act. The purpose of this notice is to allow for an additional 30 days of public comment.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB Control Number and should be sent to: HUD Desk Officer, Office of Management and Budget, New Executive Office Building, Washington, DC 20503; fax: 202-395-5806. Email:
Anna P. Guido, Reports Management Officer, QDAM, Department of Housing and Urban Development, 451 7th Street SW., Washington, DC 20410; email Anna P. Guido at
This notice informs the public that HUD is seeking approval from OMB for the information collection described in Section A.
The
As communities begin to implement ConnectHome in 2016 and connect residents to internet within their homes, this telephone survey will illuminate how families are taking advantage of ConnectHome. The telephone survey will explore ConnectHome subscribers' previous broadband access, current and planned use patterns, and current and anticipated benefits of their at-home high-speed Internet access. The survey will particularly focus on educational Internet use such as completing homework, connecting parents with educators, and applying to college.
This notice is soliciting comments from members of the public and affected parties concerning the collection of information described in Section A on the following:
(1) Whether the proposed collection of information is necessary for the proper performance of the functions of
(2) The accuracy of the agency's estimate of the burden of the proposed collection of information
(3) Ways to enhance the quality, utility, and clarity of the information to be collected; and
(4) Ways to minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology,
HUD encourages interested parties to submit comment in response to these questions.
Section 3507 of the Paperwork Reduction Act of 1995, 44 U.S.C. Chapter 35.
Fish and Wildlife Service, Interior.
Notice of availability; request for public comments.
Under the Endangered Species Act, as amended (Act), we, the U.S. Fish and Wildlife Service, invite the public to comment on an incidental take permit application for take of the federally listed American burying beetle resulting from activities associated with the geophysical exploration (seismic) and construction, maintenance, operation, repair, and decommissioning of oil and gas well field infrastructure within Oklahoma. If approved, the permit would be issued under the approved
To ensure consideration, written comments must be received on or before October 7, 2016.
You may obtain copies of all documents and submit comments on the applicant's ITP application by one of the following methods. Please refer to the proposed permit number when requesting documents or submitting comments.
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Marty Tuegel, Branch Chief, by U.S. mail at: U.S. Fish and Wildlife Service, Environmental Review Division, P.O. Box 1306, Room 6034, Albuquerque, NM 87103; or by telephone at 505-248-6651.
Under the Endangered Species Act, as amended (16 U.S.C. 1531
We invite local, State, Tribal, and Federal agencies, and the public to comment on the following application under the ICP, for incidental take of the federally listed ABB. Please refer to the appropriate permit number (
Applicant requests an amended permit for oil and gas upstream and midstream production, including geophysical exploration (seismic) and construction, maintenance, operation, repair, and decommissioning of oil and gas well field infrastructure, as well as construction, maintenance, operation, repair, decommissioning, and reclamation of oil and gas gathering, transmission, and distribution pipeline infrastructure within Oklahoma.
Written comments we receive become part of the public record associated with this action. 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 request in your comment that we withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so. We will not consider anonymous comments. All submissions from organizations or businesses, and from individuals identifying themselves as representatives or officials of organizations or businesses, will be made available for public disclosure in their entirety.
We provide this notice under section 10(c) of the Act (16 U.S.C. 1531
Bureau of Land Management, Interior.
Notice of public meeting.
In accordance with the Federal Land Policy and Management Act and the Federal Advisory Committee Act of 1972, the U.S. Department of the Interior, Bureau of Land Management (BLM) Central California Resource Advisory Council (RAC) will meet as indicated below.
A tour of tree mortality areas in the Mother Lode Field Office will be held from 8 a.m. to 1 p.m. on Thursday, Oct. 20, 2016, followed by a business meeting from 1 p.m. to 5 p.m. at the Mother Lode Field Office, 5152 Hillsdale Circle, El Dorado Hills, CA. Time for public comment is reserved from 2 p.m. to 3 p.m. The RAC will reconvene beginning at 8 a.m. on Friday, Oct 21, until business is concluded, no later than noon.
BLM Central California District Manager Este Stifel, (916) 978-4626; or BLM Public Affairs Officer David Christy, (916) 941-3146. Persons who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at (800) 877-8339, to contact the above individual during normal business hours. The FIRS is available 24 hours a day, 7 days a week, to leave a message or question with the above individual. You will receive a reply during normal business hours.
The 12-member council advises the Secretary of the Interior, through the BLM, on a variety of planning and management issues associated with public land management in the Central California District, which includes the Bishop, Bakersfield, Central Coast, Ukiah and Mother Lode Field Offices. The meeting will include consideration by the RAC of proposed campground fee increases for the Bishop Field Office. The RAC charter states:
Upon the request of the Designated Federal Official (DFO), the Council may make recommendations regarding a standard amenity recreation fee or an expanded recreation amenity fee, whenever the recommendations related to public concerns in the state or region covered by the council regarding:
(A) The implementation of a standard amenity recreation fee or an expanded amenity recreation fee or the establishment of a specific recreation fee site;
(B) The elimination of a standard amenity recreation fee or an expanded amenity recreation fee; or
(C) The expansion or limitation of the recreation fee program.
The Council may make these recommendations for the BLM when amenity recreation fees are at issue and it would facilitate implementation of the REA. With the concurrence of the Forest Service (FS) when their amenity recreation fees are at issue, the Council may also make these recommendations for BLM and/or FS if that would facilitate the effective implementation of the REA.
There will be a presentation on the fee proposal at 3 p.m. on Thursday, Oct. 20. Information on the proposed fee increase is available on the web at
Additional ongoing business will be discussed by the council. All meetings are open to the public. Members of the public may present written comments to the council. Each formal council meeting will have time allocated for public comments. Depending on the number of persons wishing to speak, and the time available, the time for individual comments may be limited. The meeting is open to the public. Individuals who plan to attend and need special assistance, such as sign language interpretation and other reasonable accommodations, should contact the BLM as provided above.
Bureau of Land Management, Interior.
Notice of public meetings.
In accordance with the Federal Land Policy and Management Act (FLPMA), the Federal Advisory Committee Act of 1972 (FACA), and the Federal Lands Recreation Enhancement Act of 2004 (FLREA), the U.S. Department of the Interior, Bureau of Land Management (BLM) Coeur d'Alene District Resource Advisory Council (RAC) will meet as indicated below.
The Coeur d'Alene District RAC will meet at the North Fork District Office of the Nez Perce/Clearwater National Forest located at 12730 Highway 12, Orofino, ID 83544. A business meeting will take place the afternoon of Tuesday, October 4, followed by a field tour of the Clearwater River Corridor on Wednesday, October 5. The business meeting will begin at 1:00 p.m. and end no later than 5:00 p.m. The public comment forum will take place from 3:30 p.m. until 4:00 p.m. The field tour will begin at 8:30 a.m. and conclude by 2:00 p.m.
Suzanne Endsley, Coeur d'Alene District, Idaho, 3815 Schreiber Way, Coeur d'Alene, Idaho, 83815, Telephone: (208) 769-5004. Email:
The 15-member RAC advises the Secretary of the Interior, through the Bureau of Land Management, on a variety of planning and management issues associated with public land management in Idaho. The meeting agenda will include a review of proposed recreation fee increases on multiple sites on the Nez Perce/Clearwater Forest, information on BLM's Planning 2.0 process and updates on projects within the Cottonwood and Coeur d'Alene Field Offices. Additional agenda topics or changes to the agenda will be announced in local press releases. The field tour will include stops at sites along the Clearwater River managed by BLM and the Clearwater Management Council. More information is available at
RAC meetings are open to the public. The public may present written comments to the Council. Each formal Council meeting will also have time allocated for hearing public comments. Depending on the number of persons wishing to comment and time available, the time for individual oral comments may be limited. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should contact the BLM as provided below.
43 CFR 1784.4-1
National Park Service, Interior.
Notice of availability, Final Environmental Impact Statement.
The National Park Service (NPS) announces the availability of the Final Environmental Impact Statement (FEIS) for the Nonfederal Oil and Gas Regulations (36 CFR part 9, subpart B) Revisions.
September 7, 2016.
Copies of the FEIS will be available for public review at
David Steensen, Chief, Geologic Resource Division, National Park Service, P.O. Box 25287, Denver, CO 80225; phone (303) 969-2014. The responsible official for this FEIS is the Associate Director, Natural Resource Stewardship and Science, 1849 C Street NW., Washington, DC 20240.
Pursuant to the National Environmental Policy Act of 1969, 42 U.S.C. 4332(2)(C), the FEIS evaluates the impacts of three alternatives, including the following alternative elements:
• Elimination of two regulatory provisions that exempt 60% of the oil and gas operations in System units. All operators in System units would be required to comply with the 9B regulations.
• Elimination of the financial assurance (bonding) cap. Financial assurance would be equal to the reasonable estimated cost of site reclamation.
• Improving enforcement authority by incorporating existing NPS penalty provisions. Law enforcement staff would have authority to write citations for noncompliance with the regulations.
• Authorizing compensation to the federal government for new access on federal lands and waters outside the boundary of an operator's mineral right.
• Reformatting the regulations to make it easier to identify an operator's information requirements and operating standards that apply to each type of operation.
National Park Service, Interior.
Notice of meeting.
This notice announces the meeting of the Boston Harbor Islands National Recreation Area Advisory Council (Council). The agenda includes updates from Boston Harbor Now and the National Park Service as well as an informational session about the Federal Advisory Committee Act (FACA).
September 19, 2016, from 5:30 p.m. to 7:30 p.m. (Eastern).
New England Aquarium, Harborside Learning Lab, Central Wharf, Boston, MA 02110.
Giles Parker, Superintendent and Designated Federal Official (DFO), Boston Harbor Islands National Recreation Area, 15 State Street, Suite 1100, Boston, MA 02109, telephone (617) 223-8669, or email
This meeting is open to the public. Those wishing to submit written comments may contact the DFO for the Council, Giles Parker, by mail at National Park Service, Boston Harbor Islands, 15 State Street, Suite 1100, Boston, MA 02109 or by email
The Council was appointed by the Director of the National Park Service pursuant to 16 U.S.C. 460kkk(g). The purpose of the Council is to advise and make recommendations to the Boston Harbor Islands Partnership with respect to the implementation of a management plan and park operations. Efforts have been made locally to ensure that the interested public is aware of the meeting dates.
Occupational Safety and Health Administration (OSHA), Labor.
Request for public comments.
OSHA solicits public comments concerning its proposal to extend the Office of Management and Budget's (OMB) approval of the information collection requirements contained in the Crawler, Locomotive, and Truck Cranes Standard (29 CFR 1910.180).
Comments must be submitted (postmarked, sent, or received) by November 7, 2016.
Theda Kenney or Todd Owen, Directorate of Standards and Guidance, OSHA, U.S. Department of Labor, Room N-3609, 200 Constitution Avenue NW., Washington, DC 20210; telephone (202) 693-2222.
The Department of Labor, as part of its continuing effort to reduce paperwork and respondent (
This program ensures that information is in the desired format, reporting burden (time and costs) is minimal, collection instruments are clearly understood, and OSHA's estimate of the information collection burden is accurate. The Occupational Safety and Health Act of 1970 (the OSH Act) (29 U.S.C. 651
The Standard specifies several paperwork requirements. The following sections describe who uses the information collected under each requirement, as well as how they use it. The purpose of each of these requirements is to prevent workers from using unsafe cranes and ropes, thereby reducing their risk of death or serious injury caused by a crane or rope failure during material handling.
Paragraph 1910.180(d) specifies that employers must prepare a written record to certify that the monthly inspection of critical items in use on cranes (such as brakes, crane hooks, and ropes) has been performed. The certification record must include the inspection date, the signature of the person who conducted the inspection, and the serial number (or other identifier) of the inspected crane. Employers must keep the certificate readily available. The certification record provides employers, workers, and OSHA compliance officers with assurance that critical items on cranes have been inspected, and that the equipment is in good operating condition so that the crane and rope will not fail during material handling. These records also enable OSHA to determine that an employer is complying with the Standard.
This provision requires employers to make available written reports of load-rating tests showing test procedures and confirming the adequacy of repairs or alterations, and to make readily available any rerating test reports. These reports inform the employer, workers, and OSHA compliance officers of a crane's lifting limitations, and provide information to crane operators to prevent them from exceeding these limits and thereby causing crane failure.
Paragraph (g)(1) requires employers to thoroughly inspect any rope in use at least once a month. The authorized person conducting the inspection must observe any deterioration resulting in appreciable loss of original strength and determine whether or not the condition is hazardous. Before reusing a rope that has not been used for at least a month because the crane housing the rope is shut down or in storage, paragraph (g)(2)(ii) specifies that employers must have an appointed or authorized person inspect the rope for all types of deterioration. Employers must prepare a certification record for the inspections required by paragraphs (g)(1) and (g)(2)(ii). These certification records must include the inspection date, the signature of the person conducting the inspection, and the identifier for the inspected rope; paragraph (g)(1) states that employers must keep the certificates “on file where readily available,” while paragraph (g)(2)(ii) requires that certificates “be . . . kept readily available.” The certification records assure employers, workers, and OSHA that the inspected ropes are in good condition.
OSHA has a particular interest in comments on the following issues:
• Whether the proposed information collection requirements are necessary for the proper performance of the Agency's functions, including whether the information is useful;
• The accuracy of OSHA's estimate of the burden (time and costs) of the information collection requirements, including the validity of the methodology and assumptions used;
• The quality, utility, and clarity of the information collected; and
• Ways to minimize the burden on employers who must comply; for example, by using automated or other technological information collection and transmission techniques.
There are no adjustments or program changes associated with the information collection requirements in the standard. The Agency is requesting that it retain its previous estimate of 30,511 burden hours. Table I describes each of the requested burden hours.
You may submit comments in response to this document as follows: (1) Electronically at
Due to security procedures, the use of regular mail may cause a significant delay in the receipt of comments. For information about security procedures concerning the delivery of materials by hand, express delivery, messenger, or courier service, please contact the OSHA Docket Office at (202) 693-2350, (TTY (877) 889-5627).
Comments and submissions are posted without change at
All submissions, including copyrighted material, are available for inspection and copying at the OSHA Docket Office. Information on using the
David Michaels, Ph.D., MPH, Assistant Secretary of Labor for Occupational Safety and Health, directed the preparation of this notice. The authority for this notice is the Paperwork Reduction Act of 1995 (44 U.S.C. 3506
National Archives and Records Administration (NARA).
Notice of new General Records Schedule (GRS) Transmittal 26.
NARA is issuing a new set of General Records Schedules (GRS) via GRS Transmittal 26. The GRS provides mandatory disposition instructions for administrative records common to several or all Federal agencies. Transmittal 26 announces changes we have made to the GRS since we published Transmittals 24 and 25 in August and September 2015. We are concurrently disseminating Transmittal 26 (the memo and the accompanying records schedules and documents) directly to each agency's records management official and have also posted it on NARA's Web site.
This transmittal is effective the date it publishes in the
You can find this transmittal on NARA's Web site at
For more information about this notice or to obtain paper copies of the GRS, contact Kimberly Keravuori, External Policy Program Manager, at
You may contact NARA's GRS Team with general questions about the GRS at
Your agency's records officer may contact the NARA appraiser or records analyst with whom your agency normally works for support in carrying out this transmittal and the revised portions of the GRS. You may access a list of the appraisal and scheduling work group and regional contacts on our Web site at
GRS Transmittal 26 announces changes to the General Records Schedules (GRS) made since NARA published GRS Transmittals 24 and 25 in August and September 2015. The GRS provide mandatory disposition instructions for records common to several or all Federal agencies.
We are completely rewriting the GRS over the course of a five-year project. Because we are phasing in the entire change from old to new gradually over five years, the GRS during this interim period will necessarily include both old and new formats. New schedules (in table format) come first in the new transmittal, followed by the old schedules (in outline format) annotated to show which items are still current and which have been superseded by new schedules. With GRS Transmittal 26, we have superseded 39 percent of the old GRS by new schedules.
Each transmittal also includes frequently asked questions (FAQs) about the GRS, the GRS Update Project, and each new schedule, as well as new-to-old crosswalks for each new schedule and an overall old-to-new crosswalk.
GRS Transmittal 26 publishes one new schedule:
It also publishes new or updated items in four schedules:
We have altered GRS 1.2, items 020-022. The note and exclusion previously (and incorrectly) shown in the overview covering all three items now modifies only item 020.
We have added five new items (012, 013, 060, 070, and 071), per DAA-GRS-2016-0001.
If you store records that fall under GRS 1.1, item 010, you should carefully review your stored holdings to determine if new item 012 correctly describes any of them. These potentially voluminous records are immediately disposable, so you may be able to save on storage fees or space.
The old-to-new crosswalk and GRS 1.1 crosswalk now show old GRS 3, item 3d (Data submitted to the Federal Procurement Data System), superseded by GRS 1.1, item 013 (Data submitted to the Federal Procurement Data System), rather than by GRS 1.1, item 010 (Financial transaction records related to procuring goods and services, paying bills, collecting debts, and accounting). Originally, GRS 3, item 3d, was among the many old schedule items folded into GRS 1.1, item 010. General Services Administration requested that we restore the stand-alone item because these records do not concern individual financial transactions, but monitor Government procurement process transparency and equity. New item 013 therefore covers the same records as old GRS 3, item 3d, but as a stand-alone item.
We have changed item 010, General ethics program records, to clarify the disposition instruction. The previous wording may have confused agencies about how long to keep some ethics records; agencies may need to keep them for longer than the old schedule seemed to indicate. Agency ethics officials provide employees with ethics advice that may pertain to a single situation or event, or that may apply to a recurring event or long-term situation. In the case of a single situation or event, the ethics determination (the ethics advice and counseling to individual employees, and supporting records) for that event is usually in effect only for the duration of that event. However, in the case of a recurring or long-term situation, the ethics determination is usually in effect throughout the period during which the recurring or long-term events occur, which could be years. The revised instruction clarifies that agencies should retain records for six years after an ethics determination is no longer in effect, rather than six years from when the agency issues the determination. For example, if the ethics official provides advice for a single, isolated event, the agency should retain the determination records for six years after that event occurs. But if the ethics official provides advice for a long-term situation that lasts for 15 years, the agency should retain the determination records for 15+6 years. Similarly, if the determination involves ethics advice about a recurring action or event an employee engages in off and on during 12 years, the agency should retain the determination records for 12+6 years. Since agencies may need to provide these records in a criminal prosecution, you should carefully note the determination date, including how long it is in effect, to ensure that the agency keeps the information available for six years after the ethics determination no longer applies.
An exclusion formerly in item 020, Access and disclosure request files (“Record copies of requested records are not covered by this item. They remain covered by their original disposal authority”), has become a note (“Record copies of requested records remain covered by their original disposal authority, but if disposable sooner than their associated access/disclosure case file, may be retained under this item for disposition with that case file”). Records may acquire a new business purpose once they become the subject of a FOIA, Privacy Act, or Mandatory Declassification Review request. The previous exclusion text did not account for this new business purpose and thus could have led to offices destroying original records when their original retention period ended instead of when the new business purpose period ended. We have clarified the coverage for items 030, 032, and 040 to eliminate confusion reported by agencies.
Items 150, 160, 161, and 170 are new.
We have altered permanent item 010's transfer date from 15 years to a 15-to-25-year band. FAQ 8 provides information about this change. In addition, we changed the cut-off for item 010 from the end of the calendar year to “In accordance with agency's business needs,” a change announced by AC 18.2016. FAQ 7 gives further information about this change. Finally, new FAQs 19 and 21-26 address how agencies may handle legacy email.
Most old GRS items are, or will be, superseded by new GRS items. A few old items, however, have outlived their usefulness and cannot be crosswalked to new items. GRS Transmittal 26 rescinds two such items.
GRS 21, items 12 (Routine Scientific, Medical, or Engineering Footage) and 19 (Routine Scientific, Medical, or Engineering Video Recordings), have fallen out of use. These media-specific items cover very technical subject matter almost always created by research and development (R&D) functions. Federal Records Centers (FRCs) held records under these codes from only two agencies. The FRCs and the agencies agreed that we should reschedule these records under agency-specific authorities. The few agencies with such functions must therefore schedule the records their R&D programs create. These two items will not crosswalk to any anticipated future GRS item, so we are rescinding them.
When you send records to an FRC for storage, you should cite the records' legal authority—the “DAA” number—in the “Disposition Authority” column of the table. For informational purposes, please include schedule and item number. For example, “DAA-GRS-2013-0001-0004 (GRS 4.3, item 020).”
NARA regulations (36 CFR 1226.12(a)) require agencies to disseminate GRS changes within six months of receipt.
Per 36 CFR 1227.12(a)(1), you must follow GRS dispositions that state they must be followed without exception.
Per 36 CFR 1227.12(a)(3), if you have an existing schedule that differs from a new GRS item that does
If you do not have an already existing agency-specific authority but wish to apply a retention period that differs from that specified in the GRS, you must create a records schedule in the Electronic Records Archives and submit it to NARA for approval.
National Endowment for the Arts, National Foundation on the Arts and Humanities.
Notice of meeting.
Pursuant to section 10(a)(2) of the Federal Advisory Committee Act (Pub. L. 92-463), as amended, notice is hereby given that the 72nd meeting of the President's Committee on the Arts and the Humanities (PCAH) will tentatively be held at the Library of Congress, 101 Independence Ave. SE., Washington, DC 20540. Please contact PCAH for specific location information. Ending time is approximate.
September 23, 2016 from 10:00 a.m. to 12:30 p.m.
Anjali Lalani of the President's Committee at (202) 682-5409 or
The meeting, on Friday, September 23rd, will begin with welcome and remarks from the co-chairs. This will be followed by updates on Committee programs (National Arts and Humanities Youth Program Awards, Turnaround Arts, National Student Poets Program, and Cultural Diplomacy). There also will be reports from the President's Committee partners and ex officio members, such as the Institute of Museum and Library Services (IMLS), National Endowment for the Arts (NEA), National Endowment for the Humanities (NEH), National Gallery of Art, John F. Kennedy Center for the Performing Arts, U.S. Department of Education, and the U.S. Department of State. The meeting will adjourn after closing remarks.
The President's Committee on the Arts and the Humanities was created by Executive Order in 1982, which currently states that the “Committee shall advise, provide recommendations to, and assist the President, the National Endowment for the Arts, the National Endowment for the Humanities, and the Institute of Museum and Library Services on matters relating to the arts and the humanities.”
Any interested persons may attend as observers, on a space available basis, but seating is limited. Therefore, for this meeting, individuals wishing to attend are advised to contact Anjali Lalani of the President's Committee seven (7) days in advance of the meeting at (202) 682-5409 or write to the Committee at Constitution Center, 400 7th St. SW., Washington, DC 20506. Further information with reference to this meeting can also be obtained from Ms. Lalani at
If you need special accommodations due to a disability, please contact the Office of AccessAbility, National Endowment for the Arts, Constitution Center, 400 7th St. SW., Washington, DC 20506, (202) 682-5532, TDY-TDD (202) 682-5496, at least seven (7) days prior to the meeting.
The ACRS Subcommittee on APR 1400 will hold a meeting on September 21-22, 2016, Room T-2B1, 11545 Rockville Pike, Rockville, Maryland.
The meeting will be open to public attendance with the exception of portions that may be closed to protect information that is proprietary pursuant to 5 U.S.C. 552b(c)(4). The agenda for the subject meeting shall be as follows:
The Subcommittee will review the APR 1400 Safety Evaluation Reports with open items—Chapters 2 (site) and 5 (reactor coolant system). The Subcommittee will hear presentations by and hold discussions with the NRC staff and Korea Hydro & Nuclear Power Company regarding this matter. The Subcommittee will gather information, analyze relevant issues and facts, and formulate proposed positions and actions, as appropriate, for deliberation by the Full Committee.
Members of the public desiring to provide oral statements and/or written comments should notify the Designated Federal Official (DFO), Christopher Brown (Telephone 301-415-7111 or Email:
Detailed meeting agendas and meeting transcripts are available on the NRC Web site at
If attending this meeting, please enter through the One White Flint North building, 11555 Rockville Pike, Rockville, MD. After registering with security, please contact Mr. Theron Brown (Telephone 240-888-9835) to be escorted to the meeting room.
Nuclear Regulatory Commission.
Exemption and combined license amendment; issuance.
The U.S. Nuclear Regulatory Commission (NRC) is granting an exemption to allow a departure from the certification information of Tier 1 of the
The granting of the exemption allows the changes to Tier 1 information asked for in the amendment. Because the acceptability of the exemption was determined in part by the acceptability of the amendment, the exemption and amendment are being issued concurrently.
Please refer to Docket ID NRC-2008-0252 when contacting the NRC about the availability of information regarding this document. You may access information related to this document, which the NRC possesses and is publicly available, using any of the following methods:
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Paul Kallan, Office of New Reactors, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-2809; email:
The NRC is granting an exemption from paragraph B of section III, “Scope and Contents,” of appendix D, “Design Certification Rule for the AP1000,” to part 52 of title 10 of the
Identical exemption documents (except for referenced unit numbers and license numbers) were issued to the licensee for VEGP Units 3 and 4 (COLs NPF-91 and NPF-92). The exemption documents for VEGP Units 3 and 4 can be found in ADAMS under Accession Nos. ML16103A412 and ML16103A419, respectively. The exemption is reproduced (with the exception of abbreviated titles and additional citations) in Section II of this document. The amendment documents for COLs NPF-91 and NPF-92 are available in ADAMS under Accession Nos. ML16103A407 and ML16103A410, respectively. A summary of the amendment documents is provided in Section III of this document.
Reproduced below is the exemption document issued to VEGP Units 3 and Unit 4. It makes reference to the combined safety evaluation that provides the reasoning for the findings made by the NRC (and listed under Item 1) in order to grant the exemption:
1. In a letter dated October 15, 2015, the licensee requested from the Commission an exemption from the provisions of 10 CFR part 52, appendix D, Section III.B, as part of license amendment request 15-005, “Diverse Actuation System (DAS) Cabinet Changes (LAR 15-005).”
For the reasons set forth in Section 3.1, “Evaluation of Exemption,” of the NRC staff's safety evaluation, which can be found in ADAMS under Accession No. ML16103A438, the Commission finds that:
A. The exemption is authorized by law;
B. the exemption presents no undue risk to public health and safety;
C. the exemption is consistent with the common defense and security;
D. special circumstances are present in that the application of the rule in this circumstance is not necessary to serve the underlying purpose of the rule;
E. the special circumstances outweigh any decrease in safety that may result from the reduction in standardization caused by the exemption; and the exemption will not result in a significant decrease in the level of safety otherwise provided by the design.
2. Accordingly, the licensee is granted an exemption from the certified DCD Tier 1 information, with corresponding changes to Appendix C of the Facility COLs as described in the licensee's request dated October 15, 2015. This exemption is related to, and necessary for, the granting of License Amendment No. 50, which is being issued concurrently with this exemption.
3. As explained in Section 5.0, “Environmental Consideration,” of the NRC staff's safety evaluation (ADAMS Accession No. ML16103A438), this exemption meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental statement or environmental assessment needs to be prepared in connection with the issuance of the exemption.
4. This exemption is effective as of the date of its issuance.
By letter dated October 15, 2015, the licensee requested that the NRC amend the COLs for VEGP, Units 3 and 4, COLs NPF-91 and NPF-92. The proposed amendment is described in Section I of this
The Commission has determined for these amendments that the application complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations. The Commission has made appropriate findings as required by the Act and the Commission's rules and regulations in 10 CFR Chapter I, which are set forth in the license amendment.
A notice of consideration of issuance of amendment to facility operating license or COL, as applicable, proposed no significant hazards consideration determination, and opportunity for a hearing in connection with these actions, was published in the
The Commission has determined that these amendments satisfy the criteria for categorical exclusion in accordance with 10 CFR 51.22. Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared for these amendments.
Using the reasons set forth in the combined safety evaluation, the staff granted the exemption and issued the amendment that the licensee requested on October 15, 2015. The exemption and amendment were issued on April 12, 2016 as part of a combined package to the licensee (ADAMS Accession No. ML16103A382).
For the Nuclear Regulatory Commission.
Economic Simplified Boiling Water Reactors (ESBWR); Notice of Meeting
The ACRS Subcommittee on ESBWR will hold a meeting on September 22, 2016, Room T-2B1, 11545 Rockville Pike, Rockville, Maryland.
The meeting will be open to public attendance.
The agenda for the subject meeting shall be as follows:
The Subcommittee will review the North Anna Unit 3 Combined License Application (COLA). The Subcommittee will hear presentations by and hold discussions with representatives of the NRC staff, Detroit Edison, and other interested persons regarding this matter. The Subcommittee will gather information, analyze relevant issues and facts, and formulate proposed positions and actions, as appropriate, for deliberation by the Full Committee.
Members of the public desiring to provide oral statements and/or written comments should notify the Designated Federal Official (DFO), Girija Shukla (Telephone 301-415-6855 or Email:
Detailed meeting agendas and meeting transcripts are available on the NRC Web site at
If attending this meeting, please enter through the One White Flint North building, 11555 Rockville Pike, Rockville, MD. After registering with security, please contact Mr. Theron Brown (240-888-9835) to be escorted to the meeting room.
It appears to the Securities and Exchange Commission that the public interest and the protection of investors require a suspension of trading in the securities of Preston Corp. (a/k/a Preston Royalty Corp.) (CIK No. 0001594219) because of questions regarding the adequacy and accuracy of available information about Preston Corp. in light of a false statement about the permitting status of a mine in the company's August 10, 2016 press release and questions regarding the adequacy and accuracy of clarifications Preston Corp. provided in a September 1, 2016, press release about the mining project. Preston Corp. is a Nevada corporation whose principal place of business is located in Austin, Texas. Its stock is quoted on OTC Link (previously “Pink Sheets”) operated by OTC Markets Group, Inc. under the ticker symbol PSNP.
The Commission is of the opinion that the public interest and the protection of investors require a suspension of trading in the securities of the above-listed company.
By the Commission.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Exchange proposes to amend prior rule change, SR-Phlx-2016-38,
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 the previously submitted filing SR-Phlx-2016-38, which contained an incorrect version of the Exchange's membership application as
Following the filing of SR-PHLX-2016-38 the Exchange continued to use the “legacy” membership application though June 30, 2016 which is contained in
The Exchange believes that its proposal is consistent with Section 6(b) of the Act,
The proposed rule change does not impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
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, it has become effective pursuant to Section 19(b)(3)(A)(iii) 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 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.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Securities and Exchange Commission (“Commission”).
Notice of an application for an order under section 6(c) of the Investment Company Act of 1940 (the “Act”) for an exemption from sections 2(a)(32), 5(a)(1), 22(d), and 22(e) of the Act and rule 22c-1 under the Act, under sections 6(c) and 17(b) of the Act for an exemption from sections 17(a)(1) and 17(a)(2) of the Act, and under section 12(d)(1)(J) for an exemption from sections 12(d)(1)(A) and 12(d)(1)(B) of the Act. The requested order would permit (a) index-based series of certain open-end management investment companies (“Funds”) to issue shares redeemable in large aggregations only (“Creation Units”); (b) secondary market transactions in Fund shares to occur at negotiated market prices rather than at net asset value (“NAV”); (c) certain Funds to pay redemption proceeds, under certain circumstances, more than seven days after the tender of shares for redemption; (d) certain affiliated persons of a Fund to deposit securities into, and receive securities from, the Fund in connection with the purchase and redemption of Creation Units; (e) certain registered management investment companies and unit investment trusts outside of the same group of investment companies as the Funds (“Funds of Funds”) to acquire shares of the Funds; and (f) certain Funds (“Feeder Funds”) to create and redeem Creation Units in-kind in a master-feeder structure.
Voya ETF Trust (the “Trust”), a Delaware statutory trust that will be registered under the Act as an open-end management investment company; Voya Investments, LLC, an Arizona limited liability company, and Directed Services LLC, a Delaware a limited liability company (together the “Initial Advisers” and individually, each an “Initial Adviser”), each registered as an investment adviser under the Investment Advisers Act of 1940; and Voya Investments Distributor, LLC (“Distributor”), an Arizona limited liability company and broker-dealer registered under the Securities Exchange Act of 1934 (“Exchange Act”).
An order granting the requested relief will be issued unless the Commission orders a hearing. Interested persons may request a hearing by writing to the Commission's Secretary and serving applicants with a copy of the request, personally or by mail. Hearing requests should be received by the Commission by 5:30 p.m. on September 26, 2016, and should be accompanied by proof of service on applicants, in the form of an affidavit, or for lawyers, a certificate of service. Pursuant to rule 0-5 under the Act, hearing requests should state the nature of the writer's interest, any facts bearing upon the desirability of a hearing on the matter, the reason for the request, and the issues contested. Persons who wish to be notified of a hearing may request notification by writing to the Commission's Secretary.
Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090; Applicants: 7337 East Doubletree Ranch Road, Suite 100, Scottsdale, Arizona 85258.
Steven I. Amchan, Senior Counsel, at (202) 551-6826, or David J. Marcinkus, Branch Chief, at (202) 551-6821 (Division of Investment Management, Chief Counsel's Office).
The following is a summary of the application. The complete application may be obtained via the Commission's Web site by searching for the file number, or for an applicant using the Company name box, at
1. Applicants request an order that would allow Funds to operate as index exchange traded funds (“ETFs”).
2. Each Fund will hold investment positions selected to correspond generally to the performance of an Underlying Index. In the case of Self-Indexing Funds, an affiliated person, as defined in section 2(a)(3) of the Act (“Affiliated Person”), or an affiliated person of an Affiliated Person (“Second-Tier Affiliate”), of the Trust or a Fund, of the Adviser, of any sub-adviser to or promoter of a Fund, or of the Distributor will compile, create, sponsor or maintain the Underlying Index.
3. Shares will be purchased and redeemed in Creation Units and generally on an in-kind basis. Except where the purchase or redemption will include cash under the limited circumstances specified in the application, purchasers will be required to purchase Creation Units by depositing specified instruments (“Deposit Instruments”), and shareholders redeeming their shares will receive specified instruments (“Redemption Instruments”). The Deposit Instruments and the Redemption Instruments will each correspond pro rata to the positions in the Fund's portfolio (including cash positions) except as specified in the application.
4. Because shares will not be individually redeemable, applicants request an exemption from section 5(a)(1) and section 2(a)(32) of the Act that would permit the Funds to register as open-end management investment companies and issue shares that are redeemable in Creation Units only.
5. Applicants also request an exemption from section 22(d) of the Act and rule 22c-1 under the Act as secondary market trading in shares will take place at negotiated prices, not at a current offering price described in a Fund's prospectus, and not at a price based on NAV. Applicants state that (a) secondary market trading in shares does not involve a Fund as a party and will not result in dilution of an investment in shares, and (b) to the extent different prices exist during a given trading day, or from day to day, such variances occur as a result of third-party market forces, such as supply and demand. Therefore, applicants assert that secondary market transactions in shares will not lead to discrimination or preferential treatment among purchasers. Finally, applicants represent that share market prices will be disciplined by arbitrage opportunities, which should prevent shares from trading at a material discount or premium from NAV.
6. With respect to Funds that effect creations and redemptions of Creation Units in kind and that are based on certain Underlying Indexes that include foreign securities, applicants request relief from the requirement imposed by section 22(e) in order to allow such Funds to pay redemption proceeds within fifteen calendar days following the tender of Creation Units for redemption. Applicants assert that the requested relief would not be inconsistent with the spirit and intent of section 22(e) to prevent unreasonable, undisclosed or unforeseen delays in the actual payment of redemption proceeds.
7. Applicants request an exemption to permit Funds of Funds to acquire Fund shares beyond the limits of section 12(d)(1)(A) of the Act; and the Funds, and any principal underwriter for the Funds, and/or any broker or dealer registered under the Exchange Act, to sell shares to Funds of Funds beyond the limits of section 12(d)(1)(B) of the Act. The application's terms and conditions are designed to, among other things, help prevent any potential (i) undue influence over a Fund through control or voting power, or in connection with certain services, transactions, and underwritings, (ii) excessive layering of fees, and (iii) overly complex fund structures, which are the concerns underlying the limits in sections 12(d)(1)(A) and (B) of the Act.
8. Applicants request an exemption from sections 17(a)(1) and 17(a)(2) of the Act to permit persons that are Affiliated Persons, or Second Tier Affiliates, of the Funds, solely by virtue of certain ownership interests, to effectuate purchases and redemptions in-kind. The deposit procedures for in-kind purchases of Creation Units and the redemption procedures for in-kind redemptions of Creation Units will be the same for all purchases and redemptions and Deposit Instruments and Redemption Instruments will be valued in the same manner as those investment positions currently held by the Funds. Applicants also seek relief from the prohibitions on affiliated transactions in section 17(a) to permit a Fund to sell its shares to and redeem its shares from a Fund of Funds, and to engage in the accompanying in-kind transactions with the Fund of Funds.
9. Applicants also request relief to permit a Feeder Fund to acquire shares of another registered investment company managed by the Adviser having substantially the same investment objectives as the Feeder Fund (“Master Fund”) beyond the limitations in section 12(d)(1)(A) and permit the Master Fund, and any principal underwriter for the Master Fund, to sell shares of the Master Fund to the Feeder Fund beyond the limitations in section 12(d)(1)(B).
10. Section 6(c) of the Act permits the Commission to exempt any persons or transactions from any provision of the Act if such exemption is necessary or appropriate in the public interest and consistent with the protection of investors and the purposes fairly intended by the policy and provisions of the Act. Section 12(d)(1)(J) of the Act provides that the Commission may exempt any person, security, or transaction, or any class or classes of persons, securities, or transactions, from any provision of section 12(d)(1) if the exemption is consistent with the public interest and the protection of investors. Section 17(b) of the Act authorizes the Commission to grant an order permitting a transaction otherwise prohibited by section 17(a) if it finds that (a) the terms of the proposed transaction are fair and reasonable and do not involve overreaching on the part of any person concerned; (b) the proposed transaction is consistent with the policies of each registered investment company involved; and (c) the proposed transaction is consistent with the general purposes of the Act.
For the Commission, by the Division of Investment Management, under delegated authority.
On March 22, 2016, NYSE Arca, Inc. (the “Exchange” or “NYSE Arca”) filed with the Securities and Exchange Commission (“Commission”), pursuant to section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
On August 29, 2016, the Exchange withdrew the proposed rule change (SR-NYSEArca-2016-15).
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Notice is hereby given, pursuant to the provisions of the Government in the Sunshine Act, Public Law 94-409, that the Securities and Exchange Commission will hold a closed meeting on Thursday, September 8, 2016 at 2 p.m.
Commissioners, Counsel to the Commissioners, the Secretary to the Commission, and recording secretaries will attend the closed meeting. Certain staff members who have an interest in the matters also may be present.
The General Counsel of the Commission, or her designee, has certified that, in her opinion, one or more of the exemptions set forth in 5 U.S.C. 552b(c)(3), (5), (7), 9(B) and (10) and 17 CFR 200.402(a)(3), (a)(5), (a)(7), (a)(9)(ii) and (a)(10), permit consideration of the scheduled matter at the closed meeting.
Chair White, as duty officer, voted to consider the items listed for the closed meeting in closed session.
The subject matter of the closed meeting will be:
Institution and settlement of injunctive actions;
Institution and settlement of administrative proceedings;
Resolution of litigation claims; and
Other matters relating to enforcement proceedings.
At times, changes in Commission priorities require alterations in the scheduling of meeting items.
For further information and to ascertain what, if any, matters have been added, deleted or postponed, please contact Brent J. Fields from the Office of the Secretary at (202) 551-5400.
On July 1, 2016, NYSE MKT LLC (“NYSE MKT” or the “Exchange”) filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
Section 19(b)(2) of the Act
The Commission finds it appropriate to designate a longer period within which to take action on the proposed rule change so that it has sufficient time to consider the proposed rule change, as modified by Amendment No. 1. Accordingly, the Commission, pursuant to Section 19(b)(2) of the Act,
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Securities and Exchange Commission (“Commission”).
Notice of an application for an order under section 6(c) of the Investment Company Act of 1940 (the “Act”) for an exemption from sections 2(a)(32), 5(a)(1), 22(d), and 22(e) of the Act and rule 22c-1 under the Act, under sections 6(c) and 17(b) of the Act for an exemption from sections 17(a)(1) and 17(a)(2) of the Act, and under section 12(d)(1)(J) for an exemption from sections 12(d)(1)(A) and 12(d)(1)(B) of the Act. The requested order would permit (a) actively-managed series of certain open-end management investment companies (“Funds”) to issue shares redeemable in large aggregations only (“Creation Units”); (b) secondary market transactions in Fund shares to occur at negotiated market prices rather than at net asset value (“NAV”); (c) certain Funds to pay redemption proceeds, under certain circumstances, more than seven days after the tender of shares for redemption; (d) certain affiliated persons of a Fund to deposit securities into, and receive securities from, the Fund in connection with the purchase and redemption of Creation Units; and (e) certain registered management investment companies and unit investment trusts outside of the same group of investment companies as the Funds (“Funds of Funds”) to acquire shares of the Funds.
Regents Park Funds, LLC (“Regents Park”), a California limited liability company that will be registered as an investment adviser under the Investment Advisers Act of 1940, Northern Lights Fund Trust IV (“Trust”), a Delaware statutory trust registered under the Act as an open-end management investment company with multiple series, and Northern Lights Distributors, LLC (“NLD”), a Nebraska limited liability company and broker-dealer registered under the Securities Exchange Act of 1934 (“Exchange Act”).
Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090; Applicants: c/o JoAnn Strasser, 41 S High Street, Columbus, Ohio 43215.
Kaitlin C. Bottock, Senior Counsel, at (202) 551-8658, or Daniele Marchesani, Branch Chief, at (202) 551-6821 (Division of Investment Management, Chief Counsel's Office).
The following is a summary of the application. The complete application may be obtained via the Commission's Web site by searching for the file number, or for an applicant using the Company name box, at
1. Applicants request an order that would allow Funds to operate as actively-managed exchange traded funds (“ETFs”).
2. Each Fund will consist of a portfolio of securities and other assets, and investment positions (“Portfolio Instruments”). Each Fund will disclose on its Web site the identities and quantities of the Portfolio Instruments that will form the basis for the Fund's calculation of NAV at the end of the day.
3. Shares will be purchased and redeemed in Creation Units and generally on an in-kind basis. Except where the purchase or redemption will include cash under the limited circumstances specified in the application, purchasers will be required to purchase Creation Units by depositing specified instruments (“Deposit Instruments”), and shareholders redeeming their shares will receive specified instruments (“Redemption Instruments”). The Deposit Instruments and the Redemption Instruments will each correspond pro rata to the positions in the Fund's portfolio (including cash positions) except as specified in the application.
4. Because shares will not be individually redeemable, applicants request an exemption from section 5(a)(1) and section 2(a)(32) of the Act that would permit the Funds to register as open-end management investment companies and issue shares that are redeemable in Creation Units only.
5. Applicants also request an exemption from section 22(d) of the Act and rule 22c-1 under the Act as secondary market trading in shares will take place at negotiated prices, not at a current offering price described in a Fund's prospectus, and not at a price based on NAV. Applicants state that (a) secondary market trading in shares does not involve a Fund as a party and will not result in dilution of an investment in shares, and (b) to the extent different prices exist during a given trading day, or from day to day, such variances occur as a result of third-party market forces, such as supply and demand. Therefore, applicants assert that secondary market transactions in shares will not lead to discrimination or preferential treatment among purchasers. Finally, applicants represent that share market prices will be disciplined by arbitrage opportunities, which should prevent shares from trading at a material discount or premium from NAV.
6. With respect to Funds that hold non-U.S. Portfolio Instruments and that effect creations and redemptions of Creation Units in kind, applicants request relief from the requirement imposed by section 22(e) in order to allow such Funds to pay redemption proceeds within fourteen calendar days
7. Applicants request an exemption to permit Funds of Funds to acquire Fund shares beyond the limits of section 12(d)(1)(A) of the Act; and the Funds, and any principal underwriter for the Funds, and/or any broker or dealer registered under the Exchange Act, to sell shares to Funds of Funds beyond the limits of section 12(d)(1)(B) of the Act. The application's terms and conditions are designed to, among other things, help prevent any potential (i) undue influence over a Fund through control or voting power, or in connection with certain services, transactions, and underwritings, (ii) excessive layering of fees, and (iii) overly complex fund structures, which are the concerns underlying the limits in sections 12(d)(1)(A) and (B) of the Act.
8. Applicants request an exemption from sections 17(a)(1) and 17(a)(2) of the Act to permit persons that are Affiliated Persons, or Second Tier Affiliates, of the Funds, solely by virtue of certain ownership interests, to effectuate purchases and redemptions in-kind. The deposit procedures for in-kind purchases of Creation Units and the redemption procedures for in-kind redemptions of Creation Units will be the same for all purchases and redemptions and Deposit Instruments and Redemption Instruments will be valued in the same manner as those Portfolio Instruments currently held by the Funds. Applicants also seek relief from the prohibitions on affiliated transactions in section 17(a) to permit a Fund to sell its shares to and redeem its shares from a Fund of Funds, and to engage in the accompanying in-kind transactions with the Fund of Funds.
9. Section 6(c) of the Act permits the Commission to exempt any persons or transactions from any provision of the Act if such exemption is necessary or appropriate in the public interest and consistent with the protection of investors and the purposes fairly intended by the policy and provisions of the Act. Section 12(d)(1)(J) of the Act provides that the Commission may exempt any person, security, or transaction, or any class or classes of persons, securities, or transactions, from any provision of section 12(d)(1) if the exemption is consistent with the public interest and the protection of investors. Section 17(b) of the Act authorizes the Commission to grant an order permitting a transaction otherwise prohibited by section 17(a) if it finds that (a) the terms of the proposed transaction are fair and reasonable and do not involve overreaching on the part of any person concerned; (b) the proposed transaction is consistent with the policies of each registered investment company involved; and (c) the proposed transaction is consistent with the general purposes of the Act.
For the Commission, by the Division of Investment Management, under delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange proposes to make changes to the Non-Standard Booth Rental Fee in the Facility Fees section of the Fees Schedule. The text of the proposed rule change is available on the Exchange's Web site (
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 the Fees Schedule. Specifically, the Exchange proposes changes to the Non-Standard Booth Rental Fee in the Facility Fees section of the Fees Schedule. In general, a “standard booth” on the Exchange refers to a portion of designated space on the trading floor of the Exchange adjacent to particular trading crowds, which may be occupied by a Trading Permit Holder (“TPH”), clerks, runners, or other support staff for operational and other business-related activities. The term “non-standard booth” generally refers to space on the trading floor of the Exchange that is set off from a trading crowd, which may be rented by a TPH for whatever support, office, back-office, or any other business-related activities for which the TPH may choose to use the space.
Currently, TPHs that rent non-standard booth space on the floor of the Exchange pay a monthly fee on a per square foot basis for use of the space. The per square foot fee that a TPH pays for non-standard booth space is determined based on the size of the booth and length of the non-standard booth lease term that the TPH entered
The Exchange notes that under the current Non-Standard Booth Rental Fee table, a TPH that rents more space for less time than another TPH may pay a lower total monthly non-standard booth rental fee than the TPH that rents less space for more time. For example, under the current Non-Standard Booth Rental Fee table, a TPH that rents a 700 square foot non-standard booth for three years will pay $4.65 per square foot or a total non-standard booth rental fee of $3,255 per month, whereas a TPH that rents an 1,000 square foot non-standard booth for one year will pay $2.83 per square foot or a total non-standard booth rental fee of $2,830 per month. Thus, as demonstrated by the above example, in many cases, a TPH may rent a bigger non-standard booth for less than a smaller non-standard booth regardless of the lease term. The Exchange believes that this regime creates an incentive for TPHs to rent more non-standard booth space than they may need.
The Exchange proposes to amend the Fees Schedule so that TPHs that rent more non-standard booth space would pay a higher non-standard booth rental fee than those that rent less space. In particular, the Exchange proposes to amend the Fees Schedule to include the following non-standard booth rental fee table:
Notably, under the proposed fee change, effective September 1, 2016, the Exchange would no longer offer discounts for longer lease terms—all lease terms would be for a period of one year.
The Exchange believes the proposed rule change is consistent with the Act and the rules and regulations thereunder applicable to the Exchange and, in particular, the requirements of Section 6(b) of the Act.
In particular, the Exchange believes that the proposed rule change is proposed rule change is consistent with Section 6(b)(4) of the Act,
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. Rather, the Exchange believes that the proposed rule change will relieve any burden on, or otherwise promote, competition by adopting a simpler fee structure for non-standard booth rental on the floor of the Exchange. Under the proposed non-standard booth rental fee all TPHs would pay the same base rate with those that rent more space paying a higher square footage fee than those that rent less space on proportional basis.
The Exchange neither solicited nor received written comments on the proposed rule change.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A) of the Act
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.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
On March 22, 2016, NYSE MKT LLC (the “Exchange” or “NYSE MKT”) filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
On August 29, 2016, the Exchange withdrew the proposed rule change (SR-NYSEMKT-2016-13).
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
The Surface Transportation Board has received a request from two professors that work for the University of Oregon and Stanford University (WB16-37— 8/25/16) for permission to use certain unmasked data from the Board's 1984-2014 Carload Waybill Samples. A copy of this request may be obtained from the Office of Economics.
The waybill sample contains confidential railroad and shipper data; therefore, if any parties object to these requests, they should file their objections with the Director of the Board's Office of Economics within 14 calendar days of the date of this notice. The rules for release of waybill data are codified at 49 CFR 1244.9.
Surface Transportation Board.
Notice of Rail Energy Transportation Advisory Committee meeting.
Notice is hereby given of a meeting of the Rail Energy Transportation Advisory Committee (RETAC), pursuant to the Federal Advisory Committee Act (FACA.
The meeting will be held on Thursday, September 22, 2016, at 9:00 a.m. E.D.T.
The meeting will be held in the Hearing Room on the first floor of the Board's headquarters at 395 E Street SW., Washington, DC 20423.
Jason Wolfe (202) 245-0239;
RETAC was formed in 2007 to provide advice and guidance to the Board, and to serve as a forum for discussion of emerging issues related to the transportation of energy resources by rail, including coal, ethanol, and other biofuels.
The meeting, which is open to the public, will be conducted in accordance with the Federal Advisory Committee Act, 5 U.S.C. app. 2; Federal Advisory Committee Management regulations, 41 CFR pt. 102-3; RETAC's charter; and Board procedures. Further communications about this meeting may be announced through the Board's Web site at
Written Comments: Members of the public may submit written comments to RETAC at any time. Comments should be addressed to RETAC, c/o Jason Wolfe, Surface Transportation Board, 395 E Street SW., Washington, DC 20423-0001 or
49 U.S.C. 1321, 49 U.S.C. 11101; 49 U.S.C. 11121.
By the Board, Rachel D. Campbell, Director, Office of Proceedings.
Tennessee Valley Authority.
60-Day notice of submission of information collection approval and request for comments.
The proposed information collection described below will be submitted to the Office of Management and Budget (OMB) for review, as required by the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 35, as amended). The Tennessee Valley Authority is soliciting public comments on this proposed collection as provided by 5 CFR 1320.8(d)(1).
Comments should be sent to the Agency Clearance Officer no later than November 7, 2016.
Requests for information, including copies of the information collection proposed and supporting documentation, should be directed to the Senior Privacy Program Manager: Christopher A. Marsalis, Tennessee Valley Authority, 400 W. Summit Hill Dr. (WT 5D), Knoxville, Tennessee 37902-1401; telephone (865) 632-2467 or by email at
Federal Aviation Administration.
Notice of availability of Final Environmental Assessment and Finding of No Significant Impact/Record of Decision.
The Federal Aviation Administration (FAA) is issuing this notice to advise the public that it has published a Final Environmental Assessment and Finding of No Significant Impact/Record of Decision for the Southern California Metroplex project.
Ryan Weller, Environmental Specialist, Western Service Center-Operations Support Group, 1601 Lind Ave. SW., Renton, WA 98057, email address:
The FAA has prepared a Final Environmental Assessment (EA) to assess the potential environmental impacts of the SoCal Metroplex project in compliance with the National Environmental Policy Act of 1969, 42 U.S.C. 4321
Availability: The EA and FONSI/ROD are available for public review at: (1) Online at:
(2) Hard-copies are available at these libraries:
(3) Electronic versions of the EA and FONSI/ROD are available at libraries in the General Study Area. A complete list of libraries with electronic copies of the EA and FONSI/ROD is available online:
Federal Transit Administration
Notice.
The U.S. Department of Transportation's Federal Transit Administration (FTA) announces the selection of projects with Fiscal Year (FY) 2016 appropriations for the Low or No Emission Grant Program (Low-No Program), as authorized by the Fixing America's Surface Transportation Act (FAST) Act. The FAST Act authorized $55 million for competitive allocations in FY 2016. On March 29, 2016, FTA published a Notice of Funding Opportunity (NOFO) (81 FR 17553) announcing the availability of Federal funding for the Low-No Program. These program funds will provide financial assistance to states and eligible public agencies for the purchase or lease of low or no emission vehicles that use advanced technologies and for related equipment or facilities use for transit revenue operations.
Successful applicants should contact the appropriate FTA Regional Office for information regarding applying for the funds or program-specific information. A list of Regional Offices can be found
In response to the NOFO, FTA received 101 proposals from 32 states requesting $446 million in Federal funds, indicating significant demand for funding for low or no emission capital projects. Project proposals were evaluated based on each applicant's responsiveness to the program evaluation criteria outlined in the NOFO.
FTA is funding 20 projects as shown in Table 1 for a total of $55 million. Recipients selected for competitive funding should work with their FTA Regional Office to finalize the grant application in FTA's Transit Award Management System (TrAMs) for the projects identified in the attached table to quickly obligate funds. Grant applications must include eligible activities applied for in the original project application. Funds must be used consistent with the competitive proposal and for the eligible capital purposes established in the NOFO and described in the FTA Circular 9030.1E.
In cases where the allocation amount is less than the proposer's total requested amount, recipients must fund the scalable project option as described in the application. If the award amount does not correspond to the scalable option, for example due to a cap on the award amount, the recipient should work with the Regional Office to reduce scope or scale of the project such that a complete phase or project is accomplished. Recipients are reminded that program requirements such as cost sharing or local match can be found in the NOFO. A discretionary project identification number has been assigned to each project for tracking purposes and must be used in the TrAMs application.
Selected projects are eligible to incur costs under pre-award authority no earlier than the date projects were publicly announced, July 26, 2016. Pre-award authority does not guarantee that project expenses incurred prior to the award of a grant will be eligible for reimbursement, as eligibility for reimbursement is contingent upon other requirements, such as planning and environmental requirements, having been met. For more about FTA's policy on pre-award authority, please see the FTA Fiscal Year 2016 Apportionments, Allocations, and Program Information and Interim Guidance found in 81 FR 7893 (February 16, 2016). Post-award reporting requirements include submission of the Federal Financial Report and Milestone progress reports in TrAMs as appropriate (see Grant Management Requirements FTA.C.5010.1D and Urbanized Area Formula Program: Program Guidance and Application Instructions C9030.1E). Recipients must comply with all applicable Federal statutes, regulations, executive orders, FTA circulars, and other Federal requirements in carrying out the project supported by the FTA grant. For selected projects that involve partnerships, the competitive selection process will be deemed to satisfy the requirement for a competitive procurement under 49 U.S.C. 5325(a). All other recipients must follow all third-party procurement guidance as described in FTA.C.4220.1F. Funds allocated in this announcement must be obligated in a grant by September 30, 2019.
National Highway Traffic Safety Administration (NHTSA), DOT
Notice.
In compliance with the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
Comments should be directed to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street NW., Washington, DC 20503, Attention NHTSA Desk Officer.
Extension of a currently approved collection.
This collection of information uses no standard forms.
Comments must be submitted on or before October 7, 2016.
Jordan Stephens, Office of the Chief Counsel, NCC-100, National Highway Traffic Safety Administration, 1200 New Jersey Avenue SE., Washington, DC 20590 (telephone: 202-366-8534). Please identify the relevant collection of information by referring to OMB Clearance Number 2127-0609 “Criminal Penalty Safe Harbor Provision.”
Since nothing in the rule requires those persons who submit reports pursuant to this rule to keep copies of any records or reports submitted to us, recordkeeping costs imposed would be zero hours and zero costs.
Send comments, within 30 days, to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street NW., Washington, DC 20503, Attention NHTSA Desk Officer.
44 U.S.C. 3506; delegation of authority at 49 CFR 1.95.
Bureau of Transportation Statistics (BTS), Office of the Assistant Secretary for Research and Technology (OST-R), U.S. Department of Transportation.
Notice and request for comments.
In compliance with the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
This collection involves information on barrier failure reporting in oil and gas operations on the Outer Continental Shelf (OCS), as referenced in recently issued Bureau of Safety and Environmental Enforcement (BSEE), U.S. Department of the Interior regulations at 30 CFR 250.730(c) (81 FR 25887, Apr. 29, 2016) and the BSEE final rule amending and updating oil and gas production safety system (30 CFR 250.803) to be published in the
BTS and BSEE have determined that it is in the public interest to collect and process barrier failure reports or other data deemed necessary to administer BSEE's safety program pertaining to barrier failures, under a pledge of confidentiality for statistical purposes only. The confidentiality of notices and reports submitted directly to BTS will be protected in accordance with the Confidential Information Protection and Statistical Efficiency Act of 2002 (CIPSEA) (44 U.S.C. 3501 note), which provides substantial additional confidentiality protections than can be provided for reports submitted directly to BSEE.
Currently, reports on equipment failures are submitted directly to BSEE with limited information related to barrier failure events and root cause. Feedback from the industry during the data collection form drafting process indicates substantial reluctance to provide detailed barrier failure event information without the additional protections of CIPSEA. Reports submitted directly to BTS under CIPSEA will use a longer data collection form that includes additional essential detail about a barrier failure event such as equipment history information, certain important event data information, and root cause information. The additional detail included in the longer form is critical to comprehensively assess failures and determine appropriate exposure denominators for risk estimates, in service of BSEE's mission to protect safety and prevent environmental harm.
Emergency processing of this collection of information is needed prior to the expiration of time periods established under the PRA because the use of normal clearance procedures is reasonably likely to result in the collection of only limited data on barrier failure events during the established PRA time periods. The use of normal clearance procedures will prevent collection of this data during the established PRA time periods, which will inhibit BSEE's ability to comprehensively assess barrier failures and risks, identify barrier failure trends, and identify causes of critical safety barrier failure events.
Information related to this ICR, including applicable supporting documentation may be obtained by contacting Demetra V. Collia, Bureau of Transportation Statistics, Office of the Assistant Secretary for Research and Technology, U.S. Department of Transportation, Office of Statistical and Economic Analysis, RTS-31, E36-302, 1200 New Jersey Avenue SE., Washington, DC 20590-0001; Phone No. (202) 366-1610; Fax No. (202) 366-3383; Email:
Comments should be submitted as soon as possible upon publication of this notice in the
The Paperwork Reduction Act of 1995 (44 U.S.C. chapter 35; as amended) and 5 CFR part 1320 require each Federal agency to obtain OMB approval to initiate an information collection activity. BTS is seeking OMB approval for the following BTS information collection activity:
In August 2013, BTS and BSEE signed an interagency agreement (IAA) to develop and implement SafeOCS, a voluntary program for confidential reporting of `near misses' occurring on the Outer Continental Shelf (OCS). The goal of the voluntary near miss reporting system is to provide BTS with essential information about accident precursors and other hazards associated with OCS oil and gas operations. Under the program, BTS will develop and publish aggregate reports that BSEE, the industry and all OCS stakeholders can use—in conjunction with incident reports and other sources of information—to reduce safety and environmental risks and continue building a more robust OCS safety culture.
On July 28, 2016, new BSEE regulations became effective, requiring in part, the reporting of well control barrier-related failure event and analysis information. Further, BSEE's final rule amending and updating oil and gas production safety systems regulations which require, in part, the reporting of SPPE failure event and analysis information will become effective on November 8, 2016. BSEE requested and BTS agreed to expand the scope of SafeOCS to include reports of equipment failure mandated by 30 CFR 250.730(c) or 30 CFR 250.803.
Both BTS and BSEE agree that reports of equipment failures are considered a type of precursor safety information that can be included in SafeOCS to provide a means of identifying industry-wide data trends on barrier failures or potential for barrier failures. This data collection will provide companies in the oil and gas industry a trusted means to report sensitive proprietary and safety information related to equipment failures and to foster trust in the confidential collection, handling, and storage of the raw data.
Feedback from the industry during the rulemaking and form drafting processes indicates substantial reluctance to provide detailed barrier failure event information without the additional protections of CIPSEA. Reports submitted directly to BSEE use an abbreviated data collection form that includes only limited information related to barrier failure events. Reports submitted directly to BTS use a longer data collection form that includes additional essential detail about a barrier failure event such as equipment history information, certain important event data information, and root cause information. The additional detail included in the longer form is critical to comprehensively assess failures and determine appropriate exposure denominators for risk estimates, in service of BSEE's mission to prevent safety and environmental harm.
BTS will use the data collected to establish a comprehensive source of barrier-related failure data for statistical purposes. With input from subject matter experts, BTS will process and analyze information on equipment failures, and publish results of such analyses in public reports. Such reports will provide BSEE, the industry, and all OCS stakeholders with essential information about failure types and modes of critical safety barriers for offshore operations, provide valuable information to identify and close gaps in risk management, and contribute to research and development of intervention programs aimed at preventing accidents and fatalities in the OCS.
BTS will: (1) Collect failure notices, failure analysis reports, and design change/modified procedures reports, as described in 30 CFR 250.730(c) and 30 CFR 250.803, submitted by industry operators, their contractors, original equipment manufacturers, and others employed in the oil and gas industry; (2) develop an analytical database using the reported data and other pertinent information; (3) conduct statistical
Respondents who report a barrier-related failure will be asked to fill out a form based upon the requirements of 30 CFR 250.730(c) and cited industry standards. They will also be asked to submit supplemental information and analysis as described in 30 CFR 250.730(c) or 30 CFR 250.803 and cited industry standards. Respondents will have the option to mail or submit the reports electronically to BTS. Respondents will be asked to provide information such as: (1) Name and contact information; (2) time and location of the failure event; (3) a short description of the failure event and operating conditions that existed at the time of the event; (4) contributing factors to the event; (5) results of an investigation or safety analysis report; (6) any design or procedural changes as a result of the reported equipment failure; and (7) any other information that might be useful in determining ways to prevents such failures from occurring.
BTS requests emergency processing of this information collection because the use of normal clearance procedures is likely to result in the collection of only limited data on barrier failure events during the established PRA time periods. The use of normal clearance procedures will prevent collection of this data during the established PRA time periods, which will inhibit BSEE's ability to comprehensively assess barrier failures and risks, identify barrier failure trends, and identify causes of critical safety barrier failure events.
The BSEE Well Control Rule failure data collection for BOP equipment was substantially driven by an event of major national significance, which also captured international attention. One important element of this event was the failure of BOP equipment. The event resulted in the deaths of 11 people and the largest oil spill in US history. It is in the public interest to commence immediate collection of the additional information on equipment history and important event data to enable a better understanding of underlying root causes.
BTS requests comments on any aspects of this information collection request, including: (1) Ways to enhance the quality, usefulness, and clarity of the collected information; and (2) ways to minimize the collection burden without reducing the quality of the information collected, including additional use of automated collection techniques or other forms of information technology.
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 estate and gift taxes; qualified disclaimers of property (Section 25.2518-2(b)).
Written comments should be received on or before November 7, 2016 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the regulations should be directed to Sara Covington, at Internal Revenue Service, Room 6526, 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 8038-T, Arbitrage Rebate, Yield Reduction and Penalty in Lieu of Arbitrage Rebate.
Written comments should be received on or before November 7, 2016 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the collection tools should be directed to Sara Covington, Internal Revenue Service, Room 6526, 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 rescission request procedures.
Written comments should be received on or before November 7, 2016 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the revenue procedure should be directed to Kerry Dennis at Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224, or through the internet at
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 2006-97, Taxation and Reporting of REIT Excess Inclusion Income.
Written comments should be received on or before November 7, 2016 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the collection tools should be directed to Sara Covington, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
Currently, the IRS is seeking comments concerning Notice 2006-97.
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 qualified conservation contributions.
Written comments should be received on or before November 7, 2016 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the regulations should be directed to Kerry Dennis at Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224, or through the internet at
The following paragraph applies to all 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 8610, Annual Low-Income Housing Credit Agencies Report, and Schedule A (Form 8610), Carryover Allocation of Low-Income Housing Credit.
Written comments should be received on or before November 7, 2016 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the forms and instructions should be directed to LaNita Van Dyke, or at Internal Revenue Service, Room 6526, 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)).
Written comments should be received on or before November 7, 2016 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue
To obtain additional information, or copies of the information collection and instructions, or copies of any comments received, contact LaNita Van Dyke, at Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224, or through the internet, at
The Department of the Treasury and the Internal Revenue Service, as part of their continuing effort to reduce paperwork and respondent burden, invite the general public and other Federal agencies to take this opportunity to comment on the proposed or continuing information collections listed below in this notice, as required by the Paperwork Reduction Act of 1995, (44 U.S.C. 3501
We invite comments on: (a) Whether the collection of information is necessary for the proper performance of the agency's functions, including whether the information has practical utility; (b) the accuracy of the agency's estimate of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on respondents, including 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 the requested information.
Currently, the IRS is seeking comments concerning the following forms, and reporting and record-keeping requirements:
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.
Pipeline and Hazardous Materials Safety Administration (PHMSA), Department of Transportation (DOT).
Notice of proposed rulemaking (NPRM).
The Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to amend the Hazardous Materials Regulations (HMR) to maintain consistency with international regulations and standards by incorporating various amendments, including changes to proper shipping names, hazard classes, packing groups, special provisions, packaging authorizations, air transport quantity limitations, and vessel stowage requirements. These revisions are necessary to harmonize the HMR with recent changes made to the International Maritime Dangerous Goods Code, the International Civil Aviation Organization's Technical Instructions for the Safe Transport of Dangerous Goods by Air, and the United Nations Recommendations on the Transport of Dangerous Goods—Model Regulations. Additionally, PHMSA proposes several amendments to the HMR that result from coordination with Canada under the U.S.-Canada Regulatory Cooperation Council.
Comments must be received by November 7, 2016.
You may submit comments by any of the following methods:
Steven Webb, Office of Hazardous Materials Standards or Aaron Wiener, International Standards, telephone (202) 366-8553, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, 1200 New Jersey Avenue SE., 2nd Floor, Washington, DC 20590-0001.
The Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to amend the Hazardous Materials Regulations (HMR; 49 CFR parts 171 to 180) to maintain consistency with international regulations and standards by incorporating various amendments, including changes to proper shipping names, hazard classes, packing groups, special provisions, packaging authorizations, air transport quantity limitations, and vessel stowage requirements. This rulemaking project is part of our ongoing biennial process to harmonize the HMR with international regulations and standards.
In this NPRM, PHMSA proposes to amend the HMR to maintain consistency with various international standards. The following are some of the more noteworthy proposals set forth in this NPRM:
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If adopted in a final rule, the amendments proposed in this NPRM will result in minimal burdens on the regulated community. The benefits achieved from their adoption include enhanced transportation safety resulting from the consistency of domestic and international hazard communication and continued access to foreign markets by U.S. manufacturers of hazardous materials. PHMSA anticipates that most of the amendments in this NPRM will result in cost savings and will ease the regulatory compliance burden for shippers engaged in domestic and international commerce, including trans-border shipments within North America.
PHMSA solicits comment from the regulated community on these amendments and others proposed in this NPRM pertaining to need, benefits and costs of international harmonization, impact on safety, and any other relevant concerns. In addition, PHMSA solicits comment regarding approaches to reducing the costs of this rule while maintaining or increasing the benefits. In its preliminary analysis, PHMSA concluded that the aggregate benefits of the amendments proposed in this NPRM justify their aggregate costs. Nonetheless, PHMSA solicits comment on specific changes (
Federal law and policy strongly favor the harmonization of domestic and international standards for hazardous materials transportation. The Federal hazardous materials transportation law (49 U.S.C. 5101
In a final rule published December 21, 1990 (Docket HM-181; 55 FR 52402), PHMSA's predecessor—the Research and Special Programs Administration (RSPA)—comprehensively revised the HMR for international harmonization with the UN Model Regulations. The UN Model Regulations constitute a set of recommendations issued by the United Nations Sub-Committee of Experts (UNSCOE) on the Transport of Dangerous Goods (TDG) and the Globally Harmonized System of Classification and Labelling of Chemicals (GHS). The UN Model Regulations are amended and updated biennially by the UNSCOE and serve as
Since publication of the 1990 rule, PHMSA has issued 11 additional international harmonization rulemakings under the following dockets: HM-215A [59 FR 67390; Dec. 29, 1994]; HM-215B [62 FR 24690; May 6, 1997]; HM-215C [64 FR 10742; Mar. 5, 1999]; HM-215D [66 FR 33316; June 21, 2001]; HM-215E [68 FR 44992; July 31, 2003]; HM-215G [69 FR 76044; Dec. 20, 2004]; HM-215I [71 FR 78595; Dec. 29, 2006]; HM-215J [74 FR 2200; Jan. 14, 2009]; HM-215K [76 FR 3308; Jan. 19, 2011]; HM-215L [78 FR 987; Jan. 7, 2013]; and HM-215M [80 FR 1075; Jan. 8, 2015]. These rulemakings were based on biennial updates of the UN Model Regulations, the IMDG Code, and the ICAO Technical Instructions.
Harmonization becomes increasingly important as the volume of hazardous materials transported in international commerce grows. It not only facilitates international trade by minimizing the costs and other burdens of complying with multiple or inconsistent safety requirements for transportation of hazardous materials, but it also enhances safety when the international standards provide an appropriate level of protection. PHMSA actively participates in the development of international standards for the transportation of hazardous materials and promotes the adoption of standards consistent with the HMR. When considering the harmonization of the HMR with international standards, PHMSA reviews and evaluates each amendment on its own merit, on its overall impact on transportation safety, and on the economic implications associated with its adoption. Our goal is to harmonize with international standards without diminishing the level of safety currently provided by the HMR or imposing undue burdens on the regulated community.
Based on recent review and evaluation, PHMSA proposes to revise the HMR to incorporate changes from the 19th Revised Edition of the UN Model Regulations, Amendment 38-16 to the IMDG Code, and the 2017-2018 Edition of the ICAO Technical Instructions, which become effective January 1, 2017.
In addition, PHMSA proposes to incorporate by reference the newest editions of various international standards. These standards incorporated by reference are authorized for use, under specific circumstances, in part 171 subpart C of the HMR. This proposed rule is necessary to incorporate revisions to the international standards and, if adopted in the HMR, will be effective January 1, 2017.
The changes to the international standards will take effect on January 1, 2017. Therefore, it is essential that a final rule incorporating these standards by reference be published no later than December 31, 2016 with an effective date of January 1, 2017. Otherwise, U.S. companies—including numerous small entities competing in foreign markets—will be at an economic disadvantage because of their need to comply with a dual system of regulations (specifically, the HMR, UN Model Regulations, and ICAO Technical Instructions). To this end, if it appears a final rule under this docket will not be published prior to January 1, 2017, PHMSA will publish a bridging document in the form of an interim final rule to amend the HMR by incorporating the 19th Revised Edition of the UN Recommendations and the 2017-2018 Edition of the ICAO Technical Instructions.
With regard to Amendment 38-16 of the IMDG Code, the International Maritime Organization (IMO) approved an implementation date of January 1, 2018. The current edition of the IMDG Code (Amendment 37-14) remains in effect through 2017; therefore, we will not include the newest version of the IMDG Code in any bridging document. The proposed incorporation by reference of the newest edition of the IMDG Code and all other changes proposed in this NPRM would be addressed in a subsequent final rule also under this docket [PHMSA-2015-0273 (HM-215N)]. Accordingly, any interim final rule will only incorporate by reference editions of the international standards that become effective on January 1, 2017.
The UN Recommendations on the Transport of Dangerous Goods—Model Regulations, Manual of Tests and Criteria, and Globally Harmonized System of Classification and Labelling of Chemicals, as well as all of the Transport Canada Clear Language Amendments, are free and easily accessible to the public on the internet, with access provided through the parent organization Web sites. The ICAO Technical Instructions, IMDG Code, and all ISO references are available for interested parties to purchase in either print or electronic versions through the parent organization Web sites. The price charged for those not freely available helps to cover the cost of developing, maintaining, hosting, and accessing these standards. The specific standards are discussed at length in the “Section-by-Section Review” for § 171.7.
In addition to various other revisions to the HMR, PHMSA proposes the following amendments to harmonize the HMR with the most recent revisions to the UN Model Regulations, ICAO Technical Instructions, and IMDG Code, as well as several amendments resulting from coordination with Canada under the U.S.-Canada RCC:
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PHMSA's goal in this rulemaking is to maintain consistency between the HMR and the international requirements. We are not striving to make the HMR identical to the international regulations but rather to remove or avoid potential barriers to international transportation.
PHMSA proposes changes to the HMR based on amendments adopted in the 19th Revised Edition of the UN Model Regulations, the 2017-2018 Edition of the ICAO Technical Instructions, and Amendment 38-16 to the IMDG Code. We are not, however, proposing to adopt all of the amendments made to the various international standards into the HMR.
In many cases, amendments to the international recommendations and regulations are not adopted into the HMR because the framework or structure makes adoption unnecessary. In other cases, we have addressed, or will address, the amendments in separate rulemaking proceedings. If we have inadvertently omitted an amendment in this NPRM, we will attempt to include the omission in the final rule; however, our ability to make changes in a final rule is limited by requirements of the Administrative Procedure Act (5 U.S.C. 553). In some instances, we can adopt a provision inadvertently omitted in the NPRM if it is clearly within the scope of changes proposed in the notice. Otherwise, in order to provide opportunity for notice and comment, the change must first be proposed in an NPRM.
The following is a list of notable amendments to the international regulations that PHMSA is not considering for adoption in this NPRM:
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The HMR currently address the packaging, hazard communication, and safe transport of salvage cylinders in § 173.3(d) and do not require approval of the Associate Administrator to do so. PHMSA considers the current salvage cylinder requirements in the HMR to provide a sufficient level of safety and adequately address the shipment of damaged and defective cylinders. It is appropriate that larger salvage cylinders go through the existing approval process. Therefore, PHMSA is not proposing changes to the current HMR requirements for salvage cylinders.
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PHMSA maintains our position as stated in the letter of interpretation (Ref. No. 14-0141) that table tennis balls are not subject to the requirements of the HMR and that the “UN 2000, Celluloid” entry only applies when the material is in a pre-manufactured state (
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The HMR, in §§ 172.402(a)(2) and 172.202(a)(3), allow and in most cases require hazardous materials exhibiting an additional subsidiary hazard to be labeled with the subsidiary hazard and to have the additional hazard described on shipping papers.
As detailed in the definition of Competent Authority Approval in § 107.1, specific regulations in subchapter A or C of the HMR are considered Competent Authority Approvals. PHMSA generally does not issue Competent Authority Approvals for situations already addressed by the HMR. Therefore, PHMSA is not proposing such changes to the current HMR requirements. Although PHMSA is not incorporating language specifically requiring a Competent Authority Approval in situations where a consignor has determined a substance has a different subsidiary risk than those identified in the HMT, we maintain the power to do so in order to facilitate commerce in situations where other competent authorities or carriers require such a document be provided.
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The existing HMR requirements for filling procedures for pressure receptacles provide a sufficient level of safety and adequately address filling requirements for pressure vessels. Therefore, PHMSA is not proposing changes to the current HMR requirements for the filling of pressure receptacles nor the adoption of any of
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While we did not oppose the adoption of this provision at ICAO, we did so recognizing that the transport environment and infrastructure is much different in parts of the world outside of the United States; and that consistent with our harmonization rulemaking considerations we would assess how best to address this topic within the HMR. During the time these amendments were being considered by ICAO, we received a special permit application that detailed more specific information than was available during the ICAO deliberations. Additionally, PHMSA received a petition for rulemaking (P-1672) requesting PHMSA harmonize with the recently adopted ICAO TI provisions for sterilization devices. Based on the lack of broad applicability, the technically specific nature of these devices and packaging systems, the significant toxicity hazard and corresponding risk to air transport, and the benefit of considering additional operational controls available to mitigate risk, it is our determination that transport in accordance with the provisions of ICAO special provision A211 are more suitably addressed through PHMSA's Special Permit program.
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On July 26, 2016, PHMSA published a NPRM [Docket No. PHMSA-2011-0140 (HM-234); 81 FR 48977] proposing to revise the § 173.309 introductory text to include cylinders used as part of a fire suppression system as a cylinder type authorized for transport in accordance with the HMT entry for fire extinguishers. The HM-234 NPRM notes the controls detailed in § 173.309 provide an acceptable level of safety regardless of whether the cylinder is equipped for use as a handheld fire extinguisher or as a component of a fixed fire suppression system.
As this issue is already being considered in an open rulemaking, we are not proposing to make any changes to the transport provisions for fire extinguishers or cylinders used in fire extinguishers. All comments, including potential impacts arising from differing domestic and international requirements, concerning transport requirements for cylinders used in fire extinguishers should be submitted to the HM-234 docket (Docket No. PHMSA-2011-0140) at
The following is a section-by-section review of the amendments proposed in this NPRM:
Section 107.502 provides general requirements for the registration of cargo tank and cargo tank motor vehicle manufacturers, assemblers, repairers, inspectors, testers, and design certifying engineers. In this NPRM, PHMSA proposes to revise paragraph (b) to provide an exception from the registration requirements for certain persons engaged in the repair, as defined in § 180.403, of DOT specification cargo tanks by facilities in Canada in accordance with the proposed § 180.413(a)(1)(iii) in this NPRM. Persons engaged in the repair of cargo tanks in Canada are required to register in accordance with the Transport Canada TDG Regulations as the Canadian registration requirements are substantially equivalent to those in part 107 subpart F of the HMR. The registration information is available on Transport Canada's Web site at
Therefore, PHMSA believes that requiring the registration of Canadian cargo tank repair facilities authorized by the proposed § 180.413(a)(1)(iii) would be unnecessarily duplicative and that excepting them from registering in accordance with part 107 subpart F would augment reciprocity without negatively impacting safety. See “Harmonization Proposals in this NPRM” and the § 180.413 entry in the “Section-by-Section Review” of this document for additional background and discussion of this proposal.
Section 107.801 prescribes approval procedures for persons seeking to engage in a variety of activities regulated by PHMSA (
Section 107.805 prescribes the requirements cylinder and pressure receptacle requalifiers need to meet in order to be approved by PHMSA. In this NPRM, PHMSA proposes to amend paragraph (a) to authorize prospective requalifiers to obtain approval by PHMSA to inspect, test, certify, repair, or rebuild TC specification cylinders; to amend paragraph (c)(2) to ensure the types of TC cylinders intended to be inspected, tested, repaired, or rebuilt at the facility are included in the application for approval to PHMSA; and to amend paragraph (d) to include various TC cylinders to the list of cylinders requiring issuance of a RIN to requalifiers.
PHMSA also proposes to amend paragraph (f) to recognize facilities authorized by Transport Canada to requalify comparable DOT specification cylinders, as well as DOT RIN holders to requalify comparable Transport Canada cylinders subject to modification of their existing approval. PHMSA recognizes that Transport Canada's approval and registration requirements are substantially equivalent to the requirements in 49 CFR part 107 subpart I and provide an equivalent level of safety. In addition, traceability is maintained based on Transport Canada's publicly available Web site at
The proposed addition of paragraph (f)(2) would allow persons who are already registered with PHMSA to perform requalification functions on DOT specification cylinders to register to requalify corresponding TC cylinder specifications without additional review by an independent inspection agency. Specifications considered equivalent are identified in the preamble to this notice (see Table 1 in § 171.12 discussion). Applicants would be required to submit all of the information prescribed in § 107.705(a) that identifies the TC, CTC, CRC, or BTC specification cylinder(s) or tube(s) to be inspected; certifies the requalifier will operate in compliance with the applicable TDG regulations; and certifies the persons performing requalification have been trained in the functions applicable to the requalifier activities.
The proposed addition of paragraph (f)(3) would allow persons who are already registered with Transport Canada to requalify corresponding DOT specification cylinders without additional application to PHMSA for approval. This proposed exception would provide cylinder owners with additional access to repair and requalification facilities in Canada, while also broadening reciprocity with Canada.
Section 171.2 prescribes general requirements for each person performing functions covered by this subchapter. PHMSA proposes to amend paragraph (h)(1) by adding the letters “TC,” “CRC,” and “BTC” to the list of specification indications that may not be misrepresented according to § 171.2(g). This is necessary as a result of proposed amendments in § 171.12 authorizing the use of various Transport Canada approved specification cylinders under certain conditions.
Section 171.7 provides a listing of all voluntary consensus standards incorporated by reference into the HMR, as directed by the “National Technology Transfer and Advancement Act of 1996.” According to the Office of Management and Budget (OMB), Circular A-119, “Federal Participation in the Development and Use of Voluntary Consensus Standards and in Conformity Assessment Activities,” government agencies must use voluntary consensus standards wherever practical in the development of regulations. Agency adoption of industry standards promotes productivity and efficiency in government and industry, expands opportunities for international trade, conserves resources, improves health and safety, and protects the environment.
PHMSA actively participates in the development and updating of consensus standards through representation on more than 20 consensus standard bodies and regularly reviews updated consensus standards and considers their merit for inclusion in the HMR. For this rulemaking, we evaluated updated international consensus standards pertaining to proper shipping names, hazard classes, packing groups, special provisions, packaging authorizations, air transport quantity limitations, and vessel stowage requirements and determined that the revised standards provide an enhanced level of safety without imposing significant compliance burdens. These standards have well-established and documented safety histories, and their adoption will maintain the high safety standard currently achieved under the HMR. Therefore, in this NPRM, PHMSA proposes to add and revise the following incorporation by reference materials:
• Paragraph (t)(1), which incorporates the
• Paragraph (v)(2), which incorporates the
• Paragraph (w), which incorporates various
• Paragraph (bb)(1), which incorporates the
• Paragraph (dd)(1), which incorporates the
• Paragraph (dd)(2), which incorporates the
• Paragraph (dd)(3) would be added to incorporate the
Section 171.8 defines terms generally used throughout the HMR that have broad or multi-modal applicability. In this NPRM, PHMSA proposes to add the following terms and definitions:
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Additionally, PHMSA proposes to amend the definitions for the following terms:
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Section 171.12 prescribes requirements for the use of the Transport Canada TDG Regulations. Under the U.S.-Canada RCC, which was established in 2011 by the President of the United States and the Canadian Prime Minister, PHMSA and Transport Canada, with input from stakeholders, identified impediments to cross-border transportation of hazardous materials. In this NPRM, PHMSA proposes to address these barriers by amending the HMR to expand recognition of cylinders, cargo tank repair facilities, and equivalency certificates in accordance with the TDG Regulations.
The HMR in § 171.12(a)(1) provide general authorizations to use the TDG Regulations for hazardous materials transported from Canada to the United States, from the United States to Canada, or through the United States to Canada or a foreign destination. PHMSA proposes to amend § 171.12(a)(1) to authorize the use of a Transport Canada equivalency certificate for such road or rail transportation of a hazardous material shipment. Consistent with existing authorizations to utilize the TDG Regulations for transportation from Canada to the United States, the proposed authorization to use a Transport Canada equivalency certificate only applies until the shipment's initial transportation ends. In other words, once a shipment offered in accordance with a Transport Canada equivalency certificate reaches the destination shown on either a transport document or package markings, transportation under the authorization in § 171.12 has ended. Any subsequent offering of packages imported under a Transport Canada equivalency certificate would have to be done in full compliance with the HMR. Transport Canada is proposing amendments to the TDG Regulations to authorize similar reciprocal treatment of PHMSA special permits.
The HMR in § 171.12(a)(4) authorize the transportation of a cylinder authorized by the Transport Canada TDG Regulations to, from, or within the United States. Currently this authorization is limited to Canadian Transport Commission (CTC) cylinders corresponding to a DOT specification cylinder and UN pressure receptacles marked with “CAN.” In this NPRM, PHMSA proposes to amend paragraph (a)(4)(ii) authorizing the use of Canadian manufactured cylinders. Specifically, PHMSA proposes to authorize the transportation of CTC, CRC, BTC, and TC cylinders that have a corresponding DOT specification cylinder prescribed in the HMR.
This proposal does not remove or amend existing requirements for DOT specification cylinders; rather, PHMSA proposes to provide that a shipper may use either a DOT specification cylinder or a TC cylinder as appropriate. The goal of these amendments is to promote
Additionally, PHMSA proposes to amend paragraph (a)(4) to authorize the filling, maintenance, testing, and use of CTC, CRC, BTC, and TC cylinders that have a corresponding DOT specification cylinder as prescribed in HMR. This authorization will extend the recognition of cylinders manufactured in Canada to be filled, used, and requalified (including rebuild, repair, reheat-treatment) in the United States in accordance with the TDG Regulations.
Table 1 lists the Canadian cylinders with the corresponding DOT specification cylinders:
A U.S.-based facility is permitted to refill and use a cylinder marked as meeting CTC specification provided it complies with the applicable requirements specified in § 171.12. In accordance with § 171.12(a)(4), when the provisions of subchapter C of the HMR require that a DOT specification or a UN pressure receptacle must be used for a hazardous material, a packaging authorized by Transport Canada's TDG Regulations may be used only if it corresponds to the DOT specification or UN standard authorized by this subchapter.
If implemented, the proposed actions described above would resolve many of the existing reciprocity issues, streamline the processing of Canadian cylinders within the United States, and alleviate unnecessary burdens on the transportation industry. DOT RIN holders may requalify and mark a TC cylinder in accordance with applicable TDG Regulations, including the application of metric markings.
Section 171.23 prescribes requirements for specific materials and packagings transported under the various international standards authorized by the HMR. PHMSA proposes to amend paragraph (a) to add TC, CTC, BTC, or CRC specification cylinders to the list of cylinders which may be transported to from or within the United States.
Section 172.101 provides the Hazardous Materials Table (HMT), as well as instructions for its use. Readers should review all changes for a complete understanding of the amendments. For purposes of the Government Printing Office's typesetting procedures, proposed changes to the HMT appear under three sections of the Table: “remove,” “add,” and “revise.” Certain entries in the HMT, such as those with revisions to the proper shipping names, appear as a “remove” and “add.” In this NPRM, PHMSA proposes to amend the HMT for the following:
• UN 0510 Rocket Motors, Division 1.4C
This new HMT entry is the result of packaged products of low power “Rocket motors” that typically meet test criteria for assignment to Division 1.4, Compatibility Group C, but are assigned to 1.3C (
• UN 3527 Polyester resin kit,
This new HMT entry addresses polyester resin kits with a base material that does not meet the definition of Class 3 (Flammable liquid) and is more appropriately classed as a Division 4.1 (Flammable solid). Presently, polyester resin kits are limited to those with a Class 3 liquid base material component and are assigned under the entry UN 3269. This new entry permits products with a viscous base component containing a flammable solvent that
• UN 3528 Engine, internal combustion, flammable liquid powered
• UN 3529 Engine, internal combustion, flammable gas powered
• UN 3530 Engine, internal combustion
These new HMT entries apply to the fuel contained in engines and machinery powered by Class 3 flammable liquids, Division 2.1 gases, and Class 9 environmentally hazardous substances. The previous entry applicable to these articles, UN 3166, is now applicable to vehicles only. As a result of the new “Engine” and “Machinery” entries, the entries “UN 3166, Engines, internal combustion,
• UN 3531 Polymerizing substance, solid, stabilized, n.o.s.
• UN 3532 Polymerizing substance, liquid, stabilized, n.o.s.
• UN 3533 Polymerizing substance, solid, temperature controlled, n.o.s.
• UN 3534 Polymerizing substance, liquid, temperature controlled, n.o.s.
These new Division 4.1 HMT entries are added for polymerizing substances that do not meet the criteria for inclusion in any other hazard class.
• Catecholborane (also known as 1, 3, 2-Benzodioxaborole)
At the ICAO DGP/25 meeting, the Panel was informed of an incident involving Catecholborane (also known as 1, 3, 2-Benzodioxaborole) that resulted in an industry recommendation to forbid transport of the substance by air unless transported in pressure receptacles and under cooled conditions. The material was classified as “UN 2924, Flammable liquid, corrosive, n.o.s.” The product properties indicated (1) that the substance decomposes to borane gas at a rate of 2 percent per week at room temperature, (2) that borane gas could ignite when in contact with moist air, and (3) that catecholborane could react violently with water. The incident occurred after transport of the substance was delayed for nine days as the result of extreme weather conditions with temperatures consistently above 33 °C (91 °F). After being stored for approximately two weeks at a low temperature at the destination, several bottles containing the substance exploded and caught fire. It was concluded that moist air entered the bottles during the long transit time under high temperatures causing a chemical reaction and pressure build up. Panel members suspected a classification problem, but they could not determine whether this was due to shipper error or a limitation in the classification criteria in the regulations. The issue was submitted to the attention of the UN Sub-Committee at the December 2016 meeting for further review and determination if a new classification was required. In the interim, a new light type entry was added to the ICAO Technical Instructions Dangerous Goods List with a new special provision (A210) assigned to “Catecholborane” and “1, 3, 2-Benzodioxaborole” forbidding the substance for transport by air on both passenger and cargo aircraft. Transport on cargo aircraft would be possible with the approval of the State of Origin and State of the Operator.
Consistent with the ICAO Technical Instructions, PHMSA proposes to add new HMT entries in italics for “Catecholborane” and “1, 3, 2-Benzodioxaborole” and to assign a new special provision A210 clarifying that this material is forbidden for air transport unless approved by the Associate Administrator.
Section 172.101(c) describes column (2) of the HMT and the requirements for hazardous materials descriptions and proper shipping names.
• PHMSA proposes to amend the proper shipping name for “UN 3269, Polyester resin kit” by adding the italicized text “liquid base material.” This is consistent with the format of the new HMT entry for polyester resin kits with a solid base material.
• PHMSA proposes to amend the proper shipping names for “UN 3151, Polyhalogenated biphenyls, liquid
Section 172.101(d) describes column (3) of the HMT and the designation of the hazard class or division corresponding to each proper shipping name.
PHMSA proposes to revise the hazard class of “UN 3507, Uranium hexafluoride, radioactive material, excepted package,
Section 172.101(g) describes column (6) of the HMT and the labels required (primary and subsidiary) for specific entries in the HMT.
Data presented to the UNSCOE in this last biennium indicated a need for the addition of a subsidiary hazard of Division 6.1 to be assigned to “UN 2815, N-Aminoethylpiperazine,” “UN 2977, Radioactive material, uranium hexafluoride, fissile,” and “UN 2978, Radioactive material, uranium hexafluoride
For the HMT entry, “UN 3507, Uranium hexafluoride, radioactive material, excepted package,
Section 172.101(h) describes column (7) of the HMT whereas § 172.102(c) prescribes the special provisions assigned to specific entries in the HMT. The particular modifications to the entries in the HMT are discussed below. See “Section 172.102 special provisions” below for a detailed discussion of the proposed additions, revisions, and deletions to the special provisions addressed in this NPRM.
• In this NPRM, new special provision 157 is proposed to be assigned to the HMT entry “UN 3527, Polyester resin kit,
• In this NPRM, new special provision 379 is proposed to be assigned to the HMT entries “UN1005, Ammonia, anhydrous” and “UN 3516, Adsorbed gas, toxic, corrosive, n.o.s.”
• In the 19th Revised Edition of the UN Model Regulations, new special provision 386 was assigned to the four new “n.o.s.” HMT entries for polymerizing substances and to the 52 named substances in the HMT that polymerize, all of which contain the text “stabilized” as part of the proper shipping name, except for “UN 2383, Dipropylamine” (see Table 2 below). This new special provision includes transport controls to avoid dangerous polymerization reactions including the use of chemical stabilization or temperature control.
In this NPRM, new special provision 387 (special provision 386 already exists) is proposed to be assigned to all 52 HMT entries.
• In this NPRM, new special provision 422 is proposed to be assigned to the HMT entries “UN 3480, Lithium ion batteries
• In this NPRM, special provision 134 is proposed to be removed from the HMT entry “UN 3072, Life-saving appliances, not self-inflating
• In this NPRM, new special provision A210 is proposed to be assigned to the new HMT italicized entries for “Catecholborane” and “1, 3, 2-Benzodioxaborole.”
• In this NPRM, new special provision A212 is proposed to be assigned to the HMT entry “UN 2031, Nitric acid
• In this NPRM, new special provision B134 is proposed to be assigned to the PG III entries in Table 4 to be consistent with revisions to the IMDG Code.
• In this NPRM, new special provision B135 is proposed to be assigned to the PG III entries in Table 5 consistent with revisions to the IMDG Code.
• In this NPRM, special provision TP1 is changed to TP2 for the following entries: “UN 2672, Ammonia solution,
• In this NPRM, special provisions T9, TP7, and TP33 are proposed to be assigned to the HMT entry “UN 1415, Lithium.” This permits UN 1415 for transportation in UN portable tanks consistent with similar Division 4.3, PG I materials.
• In this NPRM, new special provisions W31, W32, W40, and W100 are proposed to certain water-reactive substances. The proposed special provisions correspond with special packaging provisions PP31, PP31 “modified” (Packing Instruction P403), PP40, and PP100 of the IMDG Code, respectively. Table 6 contains the proposed changes listed in alphabetical order and showing the proper shipping name, UN identification number, and the proposed special provision(s).
Section 172.101(j) describes column (9) of the HMT and the quantity limitations for specific entries. Furthermore, columns (9A) and (9B) specify the maximum quantities that may be offered for transportation in one package by passenger-carrying aircraft or passenger-carrying rail car (column (9A)) or by cargo-only aircraft (column (9B)). The indication of “forbidden” means the material may not be offered for transportation or transported in the applicable mode of transport.
In this NPRM, PHMSA proposes for column (9B) a quantity limit of 75 kg for “UN 0501, Propellant, solid, Division 1.4C.” Previously, column (9B) forbid the transport of UN 0501 by cargo-only aircraft. This new quantity limit is consistent with the authorized quantity limit found in the ICAO Technical Instructions. In a working paper submitted at the 25th meeting the ICAO DGP, it was noted that while all other Division 1.4C explosives listed in the table were forbidden on passenger aircraft, only UN 0501 was also forbidden on cargo aircraft. A maximum net quantity of 75 kg per package was permitted on cargo aircraft for all other Division 1.4C explosives. It was also reported that a June 2015 meeting of the United Nations Working Group on Explosives had determined that there were no differences between the transport risks posed by UN 0501 and other Division 1.4C explosives.
Section 172.101(k) explains the purpose of column (10) of the HMT and prescribes the vessel stowage and segregation requirements for specific entries. Column (10) is divided into two columns: column (10A) [Vessel stowage] specifies the authorized stowage locations on board cargo and passenger vessels, and column (10B) [Other provisions] specifies special stowage and segregation provisions. The meaning of each code in column (10B) is set forth in § 176.84 of this subchapter.
Consistent with changes to Amendment 38-16 of the IMDG Code, PHMSA proposes numerous changes to the vessel stowage location codes shown in column (10A) of the HMT. The majority of these changes are a result of those made to the IMDG Code to ensure the safe transportation of substances requiring stabilization when transported by vessel. Table 7 contains the proposed changes listed in alphabetical order and showing the proper shipping name, UN identification number, current vessel stowage location code, and proposed vessel stowage location.
With the addition of a Division 6.1 subsidiary hazard to “UN 2815, N-Aminoethylpiperazine,” “UN 2977, Radioactive material, uranium hexafluoride, fissile,” and “UN 2978, Radioactive material, uranium hexafluoride
As a consequence of adding special provision 387, which addresses stabilization requirements to 52 existing entries in the HMT that are identified as requiring such, the IMO amended vessel stowage requirements for these entries. PHMSA proposes to add code “25” to column (10B) for the same 52 entries identified in Table 2. We note that the IMDG Code did not assign stowage provisions equivalent to code “25” to “UN 1167, Divinyl ether, stabilized” or “UN 2383, Dipropylamine.” Stowage code “25” requires these materials to be protected from sources of heat. PHMSA believes the omission of this stowage requirement in the IMDG Code to be an oversight, and we propose to add stowage code “25” to these two HMR entries.
Code “28” requires materials to which this code is assigned to be stowed away from flammable liquids. In this NPRM, consistent with changes to the IMDG Code, PHMSA proposes to remove code “28” from column (10B) for the following HMT entries: “UN 2965, Boron trifluoride dimethyl etherate”; “UN 2988, Chlorosilanes, water-reactive, flammable, corrosive, n.o.s”; “UN 1183, Ethyldichlorosilane”; “UN 1242, Methyldichlorosilane”; “UN 3490, Toxic by inhalation liquid, water-reactive, flammable, n.o.s.
Appendix B to § 172.101 lists marine pollutants regulated under the HMR. PHMSA proposes to revise the list of marine pollutants by adding six new entries to remain consistent with the IMDG Code. These changes are proposed to include those substances that were either assigned a “P” in the dangerous goods list or identified in the alphabetical index to Amendment 38-16 of the IMDG Code—based on review of evaluations for each individual material, and associated isomers where appropriate, performed by the Group of Experts on the Scientific Aspects of Marine Environmental Protection (GESAMP) and the GESAMP defining criteria for marine pollutants. The following entries are proposed to be added to the list of marine pollutants in appendix B to § 172.101: Hexanes; Hypochlorite solutions; Isoprene, stabilized; N-Methylaniline; Methylcyclohexane; and Tripropylene.
Section 172.102 lists special provisions applicable to the transportation of specific hazardous materials. Special provisions contain packaging requirements, prohibitions, and exceptions applicable to particular quantities or forms of hazardous materials. In this NPRM, PHMSA proposes the following revisions to § 172.102 special provisions:
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The proposed addition of W31 to these commodities harmonizes the HMR with changes made in Amendment 38-16 of the IMDG Code, as well as the transportation requirements of the HMR with the IMDG Code for other commodities where they were not previously harmonized. The IMDG Code has had provisions in place equivalent to proposed W31 (PP31) for certain commodities since at least 1998.
The proposed amendment would reduce the risk of fire on board cargo vessels carrying hazardous materials that can react dangerously with the ship's available water and carbon dioxide fire extinguishing systems. Some of the hazardous materials for which PHMSA is proposing to amend the vessel transportation packaging requirements react with water or moisture generating excessive heat or releasing toxic or flammable gases. Common causes for water entering into the container are: water entering through ventilation or structural flaws in the container; water entering into the containers placed on deck or in the hold in heavy seas; and water entering into the cargo space upon a ship collision or leak. If water has already entered the container, the packaging is the only protection from a potential fire.
In this NPRM, PHMSA proposes to strengthen the ability of these packages transporting water-reactive substances. PHMSA anticipates this proposed amendment could result in additional costs to domestic-only shippers but not to those shippers transporting such goods internationally. We assume that all shippers that ship hazardous materials internationally will incorporate IMDG Code-compliant packaging requirements into their business practices. These proposed amendments will increase costs for some domestic shipments of affected commodities and will require materials currently transported in packaging not already hermetically sealed to be thus packaged. Adoption of these provisions will increase the ability of these packages to perform their containment function and reduce the likelihood of a fire on board cargo vessels when used to transport substances that either generate large amounts of heat or give off flammable or toxic gases on contact with water or moisture. A 2011 Formal Safety Assessment (FSA) report presented to the IMO on shipping water-reactive materials by vessel
Regarding the cost of reducing the risk of fire from water-exposure of water-reactive materials by requiring water-resistant packaging, the FSA report concluded that the costs in relation to the amount of affected goods is likely to be high.
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Section 172.407 prescribes specifications for labels. On January 8, 2015, PHMSA published a final rule [Docket No. PHMSA-2013-0260 (HM-215M); 80 FR 1075] that required labels to have a solid line forming the inner border 5 mm from the outside edge of the label and a minimum line width of 2 mm. Transitional exceptions were provided allowing labels authorized prior to this rulemaking to be used until December 31, 2016.
The rulemaking authorized a reduction in label dimensions and features if the size of the packaging so requires. This allowance for reduction in label dimensions, consistent with the requirements for standard size labels, was contingent on the solid line forming the inner border remaining 5 mm from the outside edge of the label and the minimum width of the line remaining 2 mm. PHMSA has become aware that maintaining these inner border size requirements, while reducing the size of other label elements, may potentially result in the symbols on the reduced size labels no longer being identifiable. Consequently, we are proposing to revise paragraph (c)(i) to remove the existing inner border size requirements for reduced dimension labels and authorizing the entire label to be reduced proportionally.
In the same January 8, 2015 final rule, PHMSA authorized the continued use of a label in conformance with the requirements of this paragraph in effect on December 31, 2014, until December 31, 2016. PHMSA has been made aware that the transition period provided may not be sufficient to allow the regulated community to implement necessary changes to business practices or to deplete inventories of previously authorized labels. PHMSA is proposing to extend the transition date provided in paragraph (c)(1)(iii) until December 31, 2018 for domestic transportation in order to provide additional time for implementation and depletion of existing stocks of labels.
PHMSA proposes to create a new section containing a new Class 9 hazard warning label for lithium batteries. The label would consist of the existing Class 9 label with the addition of a figure depicting a group of batteries with one broken and emitting a flame in the lower half. This label would appear on packages containing lithium batteries required to display hazard warning labels and is intended to better communicate the specific hazards posed by lithium batteries. This action is consistent with the most recent editions of the UN Model Regulations, the ICAO Technical Instructions, and the IMDG Code. Packages of lithium batteries displaying the existing Class 9 label may continue to be used until December 31, 2018. We propose this transition period to allow shippers to exhaust existing stocks of labels and pre-printed packagings. We are not proposing any modifications to the existing Class 9 placard or the creation of a Class 9 placard specifically for cargo transport units transporting lithium batteries. PHMSA solicits comment on the appropriateness of this transition period.
Section 172.505 details the transport situations that require subsidiary placarding. Uranium hexafluoride is a volatile solid that may present both chemical and radiological hazards. It is one of the most highly soluble industrial uranium compounds and, when airborne, hydrolyzes rapidly on contact with water to form hydrofluoric acid (HF) and uranyl fluoride (UO
As previously discussed in the review of changes to § 172.102, the UN Sub-Committee determined it necessary that a 6.1 subsidiary hazard be added to the Dangerous Goods List of uranium hexafluoride entries. Currently, in addition to the radioactive placard which may be required by § 172.504(e), each transport vehicle, portable tank, or freight container that contains 454 kg (1,001 pounds) or more gross weight of non-fissile, fissile-excepted, or fissile uranium hexafluoride must be placarded with a corrosive placard on each side and each end. PHMSA proposes to add a requirement for these shipments currently requiring corrosive subsidiary placards to also placard with 6.1 poison or toxic placards. PHMSA believes the addition of this requirement will provide important hazard communication information in the event of a release of uranium hexafluoride.
Section 173.4a prescribes transportation requirements for excepted packages. In this NPRM, consistent with changes to the UN Model Regulations, PHMSA proposes to amend paragraph (e)(3) to allow required absorbent materials to be placed in either the intermediate or outer packaging. PHMSA believes this change will provide shippers of excepted packages with increased flexibility in choosing packaging configurations, while maintaining the current level of safety for the transportation of these small amounts of hazardous materials.
Section 173.9 prescribes requirements for the fumigant marking. In this NRPM, PHMSA proposes to amend § 173.9 to require that the fumigant marking and its required information are capable of withstanding a 30-day exposure to open weather conditions. This requirement is consistent with the survivability requirements for placards found in § 172.519. Amendment 38-16 of the IMDG Code was amended to require the fumigant marking to be capable of surviving three months immersion in the sea, which is consistent with IMDG Code requirements for placard survivability. PHMSA believes ensuring that the fumigant marking and its required information are robust enough to handle conditions normally incident to transportation will ensure the proper information is conveyed to those needing it. Therefore, we are proposing amendments to this section consistent with the survivability requirements for placards.
Section 173.21 describes situations in which the offering for transport or transportation of materials or packages is forbidden. Examples include materials designated as “Forbidden” in column (3) of the HMT; electrical
Section 173.40 provides general packaging requirements for toxic materials packaged in cylinders. In this NPRM, PHMSA proposes to revise paragraph (a)(1) to clarify that TC, CTC, CRC, and BTC cylinders authorized in § 171.12, except for acetylene cylinders, may be used for toxic materials.
Section 173.50 provides definitions for the various divisions of Class 1 (Explosive) materials referenced in part 173 subpart C. Paragraph (b) of this section notes that Class 1 (Explosive) materials are divided into six divisions and that the current definition of Division 1.6 states that “this division comprises articles which contain only extremely insensitive substances.” PHMSA proposes to amend the definition of Division 1.6 to note that the division is made up of articles that predominately contain extremely insensitive substances. Consistent with the recent changes to the UN Model Regulations, the new definition means that an article does not need to contain solely extremely insensitive substances to be classified as a Division 1.6 material.
Section 173.52 contains descriptions of classification codes for explosives assigned by the Associate Administrator. These compatibility codes consist of the division number followed by the compatibility group letter. Consistent with changes proposed to § 173.50 and those made in the UN Model Regulations, PHMSA proposes to amend the descriptive text for the 1.6N classification code entry in the existing table in this section to indicate that these explosives are articles predominantly containing extremely insensitive substances.
Section 173.62 provides specific packaging requirements for explosives. Consistent with the UN Model Regulations, PHMSA proposes to revise § 173.62 relating to specific packaging requirements for explosives.
In paragraph (b), in the Explosives Table, the entry for “UN 0510, Rocket motors” would be added and assigned Packing Instruction 130 consistent with other rocket motor entries.
In paragraph (c), in the Table of Packing Methods, Packing Instruction 112(c) would be revised by adding a particular packaging requirement applicable to UN 0504 requiring that metal packagings must not be used. It would also be clarified that the prohibition of metal packagings does not include packagings constructed of other material with a small amount of metal (
Section 173.121 provides criteria for the assignment of packing groups to Class 3 materials. Paragraph (b)(iv) provides criteria for viscous flammable liquids of Class 3, such as paints, enamels, lacquers and varnishes, to be placed in packing group III on the basis of their viscosity, coupled with other criteria. In this NPRM, and consistent with the changes to the UN Model regulations, PHMSA proposes to amend paragraph (b)(iv) to include additional viscosity criteria that can be used as an alternative where a flow cup test is unsuitable. Many products of the paint and printing ink industry are thixotropic in nature, which means that they are viscous at rest but become thinner on application of shear or agitation (such as stirring or brushing). During transport these viscous flammable liquids have the potential to thin under movement, but their viscosity cannot be properly characterized using a flow cup test since they will not run through the cup under static conditions. Additionally, PHMSA proposes to include an explanatory footnote to the existing table of viscosity and flash point to assist users of the section in determining kinematic viscosity.
Section 173.124 outlines defining criteria for Divisions 4.1 (Flammable solid), 4.2 (Spontaneously combustible), and 4.3 (Dangerous when wet material). Division 4.1 (Flammable solid) includes desensitized explosives, self-reactive materials, and readily combustible solids. The UN Model Regulations adopted amendments to include polymerizing materials to the list of materials that meet the definition of Division 4.1. Transport conditions for polymerizing materials are not new under the HMR. Section § 173.21 presently contains approval provisions for the transport of polymerizing materials. Unlike the present HMR requirements, the classification requirements adopted in the UN Model Regulations do not require testing to determine the rate of vapor production when heated under confinement. This rate should be the deciding factor when determining whether a polymerizing substance should be authorized for transportation in an IBC or portable tank. PHMSA proposes to add polymerizing materials to the list of materials that meet the definition of
Specifically, we propose to add a new paragraph, (a)(4), that defines polymerizing materials generally and specifies defining criteria. Polymerizing materials are materials that are liable to undergo an exothermic reaction resulting in the formation of polymers under conditions normally encountered in transport. Additionally, polymerizing materials in Division 4.1 have a self-accelerating polymerization temperature of 75 °C (167 °F) or less; have an appropriate packaging determined by successfully passing the UN Test Series E at the “None” or “Low” level or by an equivalent test method; exhibit a heat of reaction of more than 300 J/g; and do not meet the definition of any other hazard class.
Section 173.165 prescribes the transport and packaging requirements for polyester resin kits. PHMSA proposes to revise § 173.165 by adding the requirements for polyester resin kits with a flammable solid base consistent with the new HMT entry “UN 3527, Polyester resin kit, solid base material, 4.1.”
Section 173.185 prescribes transportation requirements for lithium batteries. Paragraph (c) describes alternative packaging and alternative hazard communication for shipments of up to 8 small lithium cells or 2 small batteries per package (up to 1 gram per lithium metal cell, 2 grams per lithium metal battery, 20 Wh per lithium ion cell, and 100 Wh per lithium ion battery). Specifically, PHMSA proposes to amend paragraph (c) to require strong outer packagings for small lithium cells or batteries to be rigid and to replace the current text markings that communicate the presence of lithium batteries and the flammability hazard that exists if damaged with a single lithium battery mark. Additionally, the package must be of adequate size that the lithium battery mark can be displayed on one side of the package without folding. PHMSA also proposes to require the lithium battery mark to appear on packages containing lithium cells or batteries, or lithium cells or batteries packed with, or contained in, equipment when there are more than two packages in the consignment. This requirement would not apply to a package containing button cell batteries installed in equipment (including circuit boards) or when no more than four lithium cells or two lithium batteries are installed in the equipment. We are further clarifying what is meant by the term “consignment” by defining the term used in § 173.185 as one or more packages of hazardous materials accepted by an operator from one shipper at one time and at one address, receipted for in one lot and moving to one consignee at one destination address.
Under current HMR requirements, a package of cells or batteries that meets the requirements of § 173.185(c) may be packed in strong outer packagings that meet the general requirements of §§ 173.24 and 173.24a instead of the standard UN performance packaging. Lithium batteries packed in accordance with § 173.185(c) must be packed in strong outer packagings that meet the general packaging requirements of §§ 173.24 and 173.24a and be capable of withstanding a 1.2 meter (3.9 ft) drop test without damage to the cells or batteries contained in the package, shifting of the contents that would allow battery to battery or cell to cell contact, or release of contents. Alternative hazard communication requirements also apply. The Class 9 label is replaced with text indicating the presence of lithium batteries; an indication that the package must be handled with care and that a flammability hazard exists if damaged; procedures to take in the event of damage; and a telephone number for additional information. Instead of a shipping paper, the shipper can provide the carrier with an alternative document that includes the same information as provided on the package.
In this NPRM, PHMSA proposes to replace the existing text marking requirements in § 173.185(c)(3) with a standard lithium battery mark for use in all transport modes and to remove the requirement in § 173.185(c)(3) for shippers to provide an alternative document. The lithium battery mark communicates key information (
At the 49th session of UN Sub-Committee, a late design revision to the lithium battery mark was adopted to authorize the mark on a background of “suitable contrasting color” in addition to white. This is consistent with design requirements for limited quantity marks and other marks in the Model Regulations. We are proposing to also allow the mark on a background of suitable contrasting color in addition to white.
Additionally, PHMSA proposes to amend § 173.185(c)(2) to specify that outer packagings used to contain small lithium batteries must be rigid and of adequate size so the handling mark can be affixed on one side without the mark being folded. The HMR currently do not prescribe minimum package dimensions or specific requirements for package performance other than the requirements described in §§ 173.24 and 173.24a. We are aware of several instances in which either the package dimensions were not adequate to accommodate the required marks and labels or the package was not sufficiently strong to withstand the rigors of transport. These proposals will enhance the communication and recognition of lithium batteries and better ensure that packaging is strong enough to withstand normal transport conditions.
PHMSA proposes amendments to § 173.185(e) to permit the transport of prototype and low production runs of lithium batteries contained in equipment. These proposals are mostly consistent with amendments adopted into the 19th Revised Edition of the UN Model Regulations and Amendment 38-16 to the IMDG Code, which authorize the transportation of prototype and low production runs of lithium batteries contained in equipment in packaging tested to the PG II level. The ICAO TI authorizes the transportation of prototype and low production runs of lithium batteries contained in equipment in packaging tested to the PG I level. PHMSA proposes to continue to require prototype and low production batteries to be placed in packaging tested to the PG I performance level. PHMSA believes that the higher integrity packaging provides an
Consistent with changes to the UN Model Regulations, the IMDG Code, and the ICAO Technical Instructions, PHMSA proposes to add new paragraph (e)(7) to require shipments of low production runs and prototype lithium batteries to note conformance with the requirements of § 173.185(e) on shipping papers.
Additionally, PHMSA proposes amendments to § 173.185(f)(4) to harmonize with a requirement in the 19th Revised Edition of the UN Model Regulations that the “Damaged/defective lithium ion battery” and/or “Damaged/defective lithium metal battery” marking as appropriate be in characters at least 12 mm (.47 inch) high.
Section 173.217 establishes packaging requirements for dry ice (carbon dioxide, solid). Paragraph (c) prescribes additional packaging requirements for air transport. Consistent with the ICAO Technical Instructions, in this NPRM, PHMSA proposes to remove the term “other type of pallet” in paragraph (c)(3) that excepts dry ice being used as a refrigerant for other non-hazardous materials from the quantity limits per package shown in columns (9A) and (9B) of the § 172.101 HMT.
A working paper submitted to the October 2014 ICAO Dangerous Goods Panel meeting noted that the term “other type of pallet” was used in conjunction in various parts of the ICAO Technical Instructions with the terms “package,” “overpack,” or “unit load device,” which were all defined in the ICAO Technical Instructions. The ICAO Technical Instructions do not have a specific definition for “other type of pallet,” as the term is understood to represent devices that are widely used in transport, such as wooden skids or pallets that allow the use of a forklift for ease of moving packages around and to prevent damage to the contents of the skid or pallet. The definition for “overpack” already addresses the intent of the term “other type of pallet,” so it was agreed that the term “other type of pallet” was redundant and that references to it would be removed.
Section 173.220 prescribes transportation requirements and exceptions for internal combustion engines, vehicles, machinery containing internal combustion engines, battery-powered equipment or machinery, and fuel cell-powered equipment or machinery. The UN Model Regulations adopted amendments to the existing UN 3166 engine and vehicle entries during the last biennium. These changes are continuations of efforts undertaken by the UN Sub-Committee to ensure appropriate hazard communication is provided for engines containing large quantities of fuels.
The 17th Edition of the UN Model Regulations added special provision 363, which required varying levels of hazard communication depending on the type and quantity of fuel present, in attempts to ensure the hazards associated with engines containing large quantities of fuel were sufficiently communicated. PHMSA did not adopt the provisions found in special provision 363 at the time they were introduced.
As previously discussed in the review of the new proposed HMT entries, the existing UN 3166 identification number was maintained for the various vehicle entries in the Model Regulations, and three new UN identification numbers and proper shipping names were created for engines or machinery internal combustion and were assigned a hazard classification based on the type of fuel used. The three new UN numbers and proper shipping names are as follows: A Class 3 entry “UN 3528, Engine, internal combustion engine, flammable liquid powered,
Consistent with the UN Model Regulations, PHMSA proposes to add to the HMR the new UN identification numbers and proper shipping names for engines and machinery. PHMSA proposes to maintain the existing transportation requirements and exceptions for engines and machinery found in § 173.220 for all modes of transportation other than vessel. To harmonize as closely as possible with Amendment 38-16 of the IMDG Code, PHMSA proposes the following amendments to § 173.220: Amending paragraph (b)(1) to include a reference to engines powered by fuels that are marine pollutants but do not meet the criteria of any other Class or Division; amending paragraph (b)(4)(ii) to include a reference to the proposed new § 176.906 containing requirements for shipments of engines or machinery offered for transportation by vessel; amending paragraph (d) to authorize the transportation of securely installed prototype or low production run lithium batteries in engines and machinery by modes of transportation other than air; and adding paragraph (h)(3) to include references to existing and proposed exceptions for vehicles, engines, and machinery in §§ 176.905 and 176.906.
ICAO adopted a provision that requires battery powered vehicles that could be handled in other than an upright position to be placed into a strong rigid outer package. ICAO adopted this provision to ensure that small vehicles, particularly those powered by lithium batteries are adequately protected from damage during transport. PHMSA proposes to amend paragraphs (c) and (d) consistent with this requirement. While this international requirement is specific to air transport, we believe there is benefit to applying this requirement for transportation by all transport modes.
Section 173.221 prescribes the packaging requirements for Polymeric beads (or granules), expandable,
Section 173.225 prescribes packaging requirements and other provisions for organic peroxides. Consistent with the UN Model Regulations, PHMSA proposes to revise the Organic Peroxide Table in paragraph (c) by amending the entries for: “Dibenzoyl peroxide,” “tert-Butyl cumyl peroxide,” “Dicetyl peroxydicarbonate,” and “tert-Butyl peroxy-3,5,5-trimethylhexanoate.” We propose to revise the Organic Peroxide IBC Table in paragraph (e) to maintain alignment with the UN Model Regulations by adding new entries for “tert-Butyl cumyl peroxide” and
Section 173.301b contains additional general requirements for shipment of UN pressure receptacles. PHMSA proposes to amend paragraph (a)(2) to include the most recent ISO standard for UN pressure receptacles and valve materials for non-metallic materials in ISO 11114-2:2013. Additionally, we propose to amend paragraph (c)(1) to include the most recent ISO standard on cylinder valves ISO 10297:2014. This paragraph also contains end dates for when the manufacture of cylinders and service equipment is no longer authorized in accordance with the outdated ISO standard. Finally, we propose to amend § 173.301b(g) to amend a reference to marking requirements for composite cylinders used for underwater applications. The current reference to the “UW” marking in § 173.301b(g) direct readers to § 178.71(o)(17). The correct reference for the “UW marking is § 178.71(q)(18). We propose to make this editorial change in this NPRM.
Section 173.303 prescribes requirements for charging of cylinders with compressed gas in solution (acetylene). PHMSA proposes to amend paragraph (f)(1) to require UN cylinders for acetylene use to comply with the current ISO standard ISO 3807:2013. This paragraph also contains end dates for when the manufacture of cylinders and service equipment is no longer authorized in accordance with the outdated ISO standard.
Section 173.304b prescribes filling requirements for liquefied gases in UN pressure receptacles. The UN Model Regulations amended packing instruction P200 by adding requirements for liquefied gases charged with compressed gases. In this NPRM, PHMSA proposes to amend § 173.304b specifically by adding a new paragraph (b)(5) to include filling limits when a UN cylinder filled with a liquefied gas is charged with a compressed gas. We are not proposing similar filling limits for DOT specification cylinders filled with a liquefied gas and charged with a compressed gas, as we feel the situation is adequately addressed by the requirements found in § 173.301(a)(8).
Section 173.310 provides the transport conditions for certain specially designed radiation detectors containing a Division 2.2 (Non-flammable) gas. The 19th Revised Edition of the UN Model Regulations added a new special provision 378 applicable to radiation detectors containing certain Division 2.2 gases. Special provision 378 outlines conditions for the use of a non-specification pressure receptacle and strong outer packaging requirements. As § 173.310 currently prescribes similar transport conditions for radiation detectors containing Division 2.2 gases, we are not proposing to add a new special provision.
Consistent with special provision 378 of the UN Model Regulations, PHMSA proposes the following revisions to the transport conditions in § 173.310: [1] In the section header, clarify that Division 2.2 gases must be in non-refillable cylinders; [2] in (b), increase the maximum design pressure from 4.83 MPa (700 psig) to 5.00 MPa (725 psig) and increase the capacity from 355 fluid ounces (641 cubic inches) to 405 fluid ounces (731 cubic inches); [3] in new paragraph (d), require specific emergency response information to accompany each shipment and be available from the associated emergency response telephone number; [4] in new paragraph (e), require that transport in accordance with this section be noted on the shipping paper; and [5] in new paragraph (f), except radiation detectors, including detectors in radiation detection systems, containing less than 1.69 fluid ounces (50 ml) capacity, from the requirements of the subchapter if they conform to (a) through (d) of this section.
Section 173.335 contains requirements for cylinders filled with chemicals under pressure. The 19th Revised Edition of the UN Recommendations includes new instructions in P200 and P206 on how to calculate the filling ratio and test pressure when a liquid phase of a fluid is charged with a compressed gas. PHMSA proposes to revise the requirements of § 173.335 for chemical under pressure n.o.s. to include a reference to § 173.304b, which specifies additional requirements for liquefied compressed gases in UN pressure receptacles. In another proposed amendment in this NPRM, PHMSA proposes to amend § 173.304b specifically by adding a new paragraph (b)(5) to include these filling and test pressure requirements consistent with the UN Recommendations.
Section 175.10 specifies the conditions for which passengers, crew members, or an operator may carry hazardous materials aboard an aircraft. Paragraph (a)(7) permits the carriage of medical or clinical mercury thermometers, when carried in a protective case in carry-on or checked baggage. Consistent with revisions to the ICAO Technical Instructions, in this NPRM, PHMSA proposes to revise paragraph (a)(7) by limiting thermometers containing mercury to checked baggage only. This revision was based on a proposal submitted to the ICAO DGP/25 meeting that highlighted two incidents involving leakage of mercury from thermometers carried in the cabin and addressed the cost and difficult process of cleaning a spill. The proposal noted that digital thermometers had become widely available, and as such, there was no longer a need to allow mercury thermometers in the cabin or cockpit. The Panel discussed whether mercury thermometers should also be banned from checked baggage but agreed to retain the provision for checked baggage on the basis that there were parts of the world where their use was more prevalent.
Section 175.25 prescribes the notification that operators must provide to passengers regarding restrictions on the types of hazardous material they may or may not carry aboard an aircraft on their person or in checked or carry-on baggage. Passenger notification of hazardous materials restrictions addresses the potential risks that passengers can introduce on board aircraft. PHMSA's predecessor, the Materials Transportation Bureau, introduced passenger notification requirements in 1980 [Docket No. HM-166B; 45 FR 13087]. Although this section had been previously amended to account for ticket purchase or check-in via the Internet, new technological innovations have continued to outpace these provisions. Notwithstanding the
The 2017-2018 ICAO Technical Instructions has removed prescriptive requirements concerning how the information concerning dangerous goods that passengers are forbidden to transport are required to be conveyed to passengers by removing references to “prominently displayed” and “in sufficient numbers.” Additional ICAO Technical Instructions changes include removal of prescriptive requirements that the information be in “text or pictorial form” when checking in remotely, or “pictorial form” when not checking in remotely. ICAO's decision to move to a performance-based requirement will account for changes in technology as well as the unique characteristics of some air carrier operations. ICAO noted that these provisions lagged behind the latest technology and could sometimes hinder the effectiveness and efficiency of notifying passengers about hazardous materials. To account for the utilization of different technologies as well as air carrier specific differences in operating or business practices, ICAO adopted changes that require air carriers to describe their procedures for informing passengers about dangerous goods in their operations manual and/or other appropriate manuals.
PHMSA agrees with this approach and proposes to harmonize with the amendments made to the ICAO Technical Instructions part 7; 5.1. Harmonization is appropriate not only to account for evolving technologies or air carrier specific conditions, but also because we believe that this amendment will result in a more effective notification to passengers.
Under the proposed revisions to § 175.25, in accordance with 14 CFR parts 121 and 135, air carriers operating under 14 CFR parts 121 or 135 will need to describe in an operations manual and/or other appropriate manuals in accordance with the applicable provisions of 14 CFR. The manual(s) will be required to provide procedures and information necessary to allow personnel to implement and maintain their air carrier's specific passenger notification system. Aside from the manual provisions, all persons engaging in for hire air transportation of passengers will continue to be subject to § 175.25.
Section 175.33 establishes requirements for shipping papers and for the notification of the pilot-in-command when hazardous materials are transported by aircraft. The pilot notification requirements of part 7;4.1.1.1 of the ICAO Technical Instructions include an exception for consumer commodities (ID8000) to allow for the average gross mass of the packages to be shown instead of the actual gross mass of each individual package. This exception is limited to consumer commodities offered to the operator by the shipper in a unit load device (ULD). Consistent with the ICAO Technical Instructions packing instruction applicable to consumer commodities (PI Y963), which permits the shipper to show on the shipping paper either the actual gross mass of each package or the average gross mass of all packages in the consignment, the notification to the pilot-in-command requirement for consumer commodities was revised to remove the exception applicability to ULDs only. This exception did not previously exist under the HMR. In this NPRM, PHMSA proposes to revise § 175.33(a)(3) by adding the text “For consumer commodities, the information provided may be either the gross mass of each package or the average gross mass of the packages as shown on the shipping paper.” This revision would align the consumer commodity notification of the pilot-in-command requirements in the HMR with the ICAO Technical Instructions.
Section 175.900 prescribes the handling requirements for air carriers that transport dry ice. Consistent with the ICAO Technical Instructions, PHMSA proposes to remove the term “other type of pallet” with regard to packages containing dry ice prepared by a single shipper. See “Section 173.217” of this rulemaking for a detailed discussion of the proposed revision.
Section 176.83 prescribes segregation requirements applicable to all cargo spaces on all types of vessels and to all cargo transport units. Paragraph (a)(4)(ii) has several groups of hazardous materials of different classes, which comprise a group of substances that do not react dangerously with each other and that are excepted from the segregation requirements of § 176.83. Consistent with changes made in Amendment 38-16 of the IMDG Code, PHMSA proposes to add a new group of hazardous materials that do not react dangerously with each other to this paragraph. The following materials are proposed for new paragraph (a)(4)(ii)(C); “UN 3391, Organometallic substance, solid, pyrophoric”; “UN 3392, Organometallic substance, liquid, pyrophoric”; “UN 3393, Organometallic substance, solid, pyrophoric, water-reactive”; “UN 3394, Organometallic substance, liquid, pyrophoric, water-reactive”; “UN 3395, Organometallic substance, solid, water-reactive”; “UN 3396, Organometallic substance, solid, water-reactive, flammable”; “UN 3397, Organometallic substance, solid, water-reactive, self-heating”; “UN 3398, Organometallic substance, liquid, water-reactive”; “UN 3399, Organometallic substance, liquid, water-reactive, flammable”; and “UN 3400, Organometallic substance, solid, self-heating.”
Section 176.84 prescribes the meanings and requirements for numbered or alpha-numeric stowage provisions for vessel shipments listed in column (10B) of the § 172.101 HMT. The provisions in § 176.84 are broken down into general stowage provisions, which are defined in the “table of provisions” in paragraph (b), and the stowage provisions applicable to vessel shipments of Class 1 explosives, which are defined in the table to paragraph (c)(2). PHMSA proposes to create a new stowage provision 149 and assign it to the new UN 3528 engines or machinery powered by internal combustion engine flammable liquid entry. This new stowage provision will require engines or machinery containing fuels with a flash point equal or greater than 23 °C (73.4 °F) to be stowed in accordance with the stowage requirements of stowage Category A. Engines and machinery containing fuels with a flash point less than 23 °C (73.4 °F) are required to comply with the requirements of stowage Category E.
Additionally, consistent with Amendment 38-16 of the IMDG Code, PHMSA proposes to create a new stowage provision 150 to replace existing stowage provision 129 for “UN 3323, Radioactive material, low specific activity (LSA-III)
Section 176.905 prescribes transportation requirements and exceptions for vessel transportation of motor vehicles and mechanical equipment. PHMSA proposes to revise § 176.905 to update the transport
The following changes are proposed to the transport requirements for vehicles transported by vessel: [1] In paragraph (a)(2) for flammable liquid powered vehicles, the requirement that flammable liquid must not exceed 250 L (66 gal) unless otherwise approved by the Associate Administrator; [2] in paragraph (a)(4), the authorization to transport vehicles containing prototype or low production run batteries securely installed in vehicles; [3] also in paragraph (a)(4), the requirement that damaged or defective lithium batteries must be removed and transported in accordance with § 173.185(f); and [4] in paragraph (i)(1)(i), the inclusion of text to ensure lithium batteries in vehicles stowed in a hold or compartment designated by the administration of the country in which the vessel is registered as specially designed and approved for vehicles have lithium batteries that have successfully passed the tests found in the UN Manual of Tests and Criteria (except for prototypes and low production runs).
Consistent with changes made in Amendment 38-16 of the IMDG Code, PHMSA proposes the creation of a new section § 176.906 to prescribe transportation requirements for engines and machinery. Requirements found in paragraphs (a)-(h) are identical to existing requirements for engines and machinery contained in § 176.905, and their reproduction in this section is made necessary by the splitting of the provisions for engines/machinery and vehicles. Paragraph (i) contains exceptions that are divided into two separate categories: [1] Engines and machinery meeting one of the conditions provided in (i)(1), which are not subject to the requirements of subchapter C of the HMR; and [2] engines and machinery not meeting the conditions provided in (i)(1), which are subject to the requirements found in (i)(2) that prescribe general conditions for transport and varying degrees of hazard communication required for engines and machinery based on the actual fuel contents and capacity of the engine or machinery.
A summary of the proposed hazard communication requirements for vessel transportation of engines and machinery that are not empty of fuel based on fuel content and capacity are provided in Tables 8 and 9. The additional hazard communication requirements column indicates requirements that would differ from existing hazard communication requirements for engines or machinery.
Section 178.71 prescribes specifications for UN pressure receptacles. Consistent with the UN Model Regulations, PHMSA proposes to amend paragraphs (d)(2), (h), (k)(2), and (l)(1) to reflect the adoption of the latest ISO standards for the design, construction, and testing of gas cylinders and their associated service equipment. In paragraph (l)(1), we propose to require that composite cylinders be designed for a design life of not less than 15 years, as well as that composite cylinders and tubes with a design life longer than 15 years must not be filled after 15 years from the date of manufacture, unless the design has successfully passed a service life test program. The service life test program must be part of the initial design type approval and must specify inspections and tests to demonstrate that cylinders manufactured accordingly remain safe to the end of their design life. The service life test program and the results must be approved by the competent authority of the country of approval that is responsible for the initial approval of the cylinder design. The service life of a composite cylinder or tube must not be extended beyond its initial approved design life. These paragraphs also contain proposed end dates for when the manufacture of cylinders and service equipment is no longer authorized in accordance with the outdated ISO standard.
Additionally, consistent with the UN Model Regulations, PHMSA proposes to revise paragraph (o)(2) to adopt the current ISO standard relating to material compatibility and to add paragraph (g)(4) to adopt the current ISO standard relating to design, construction, and testing of stainless steel cylinders with an Rm value of less than 1,100 MPa.
Finally, we propose to revise paragraphs (q) and (r) to indicate the required markings for composite cylinders and tubes with a limited design life of 15 years or for cylinders and tubes with a design life greater than 15 years, or a non-limited design life.
Section 178.75 contains specifications for Multiple-element gas containers (MEGCs). Consistent with the UN Model Regulations, PHMSA proposes to renumber existing paragraph (d)(3)(iv) as (d)(3)(v) and to add a new paragraph (d)(3)(iv) to incorporate ISO 9809-
Section 178.1015 prescribes general standards for the use of flexible bulk containers (FBCs). Consistent with changes to the UN Model Regulations, PHMSA proposes to revise paragraph (f) to require that FBCs be fitted with a vent that is designed to prevent the ingress of water in situations where a dangerous accumulation of gases may develop absent such a vent. It is our understanding that only one particular material authorized for transportation in FBCs—UN3378, Sodium carbonate peroxyhydrate—is known to decompose causing a dangerous accumulation of gas.
Section 180.205 outlines general requirements for requalification of specification cylinders. PHMSA proposes an amendment to paragraph (c) to require that Transport Canada cylinders be requalified and marked in accordance with the Transport Canada TDG Regulations. This amendment is necessary to ensure that RIN holders utilize the TDG Regulations when requalifying and marking Transport Canada cylinders.
Section 180.207 prescribes requirements for requalification of UN pressure receptacles. Consistent with changes to the UN Model Regulations, PHMSA proposes to revise paragraph (d)(3) to incorporate ISO 10462:2013 concerning requalification of dissolved acetylene cylinders. This paragraph also includes an authorization to requalify acetylene cylinders in accordance with the current ISO standard until December 31, 2018.
Section 180.413 provides the requirements for the repair, modification, stretching, rebarrelling, or mounting of specification cargo tanks. Currently, § 180.413(a)(1) requires that each repair of a specification cargo tank must be performed by a repair facility holding a valid National Board Certificate of Authorization for use of the National Board “R” stamp and must be made in accordance with the edition of the National Board Inspection Code in effect at the time the work is performed. “Repair” is defined in § 180.403 as any welding on a cargo tank wall done to return a cargo tank or a cargo tank motor vehicle to its original design and construction specification, or to a condition prescribed for a later equivalent specification in effect at the time of the repair. As discussed in the “Harmonization Proposals in this NPRM” section, stakeholders participating in the U.S.-Canada RCC identified this requirement as being burdensome to United States carriers who also operate in Canada. In accordance with the Transport Canada TDG Regulations, a facility in Canada can perform a repair on a specification cargo tank if it holds either a valid National Board Certificate of Authorization for use of the National Board “R” stamp or a valid Certificate of Authorization from a provincial pressure vessel jurisdiction for repair. The latter authorization becomes problematic for United States carriers requiring the repair of a DOT specification cargo tank while in Canada. Section 180.413 currently only authorizes the repair of a DOT specification cargo tank by a facility holding a valid National Board Certificate of Authorization for use of the National Board “R” stamp. If a DOT specification cargo tank is repaired in Canada at a facility holding a Certificate of Authorization from a provincial pressure vessel jurisdiction for repair and not a National Board Certificate of Authorization for use of the National Board “R” stamp, the DOT specification of the cargo tank is placed in jeopardy.
Based on this input from RCC stakeholders, PHMSA conducted a comparison of the HMR requirements for the repair of specification cargo tanks and the corresponding requirements of the Transport Canada TDG Regulations. PHMSA finds that the requirements for the repair of a specification cargo tank conducted in accordance with the Transport Canada TDG Regulations by a facility in Canada holding a valid Certificate of Authorization from a provincial pressure vessel jurisdiction for repair provides for at least an equivalent level of safety as those provided by the HMR. Further, the Transport Canada TDG Regulations authorize the repair of TC specification cargo tanks by facilities in the U.S. that are registered in accordance with part 107 subpart F.
Accordingly, PHMSA proposes to expand the authorization for the repair of DOT specification cargo tanks by revising § 180.413(a)(1). Specifically, PHMSA proposes to add a new subparagraph (iii) authorizing a repair, as defined in § 180.403, of a DOT specification cargo tank used for the transportation of hazardous materials in the United States performed by a facility in Canada in accordance with the Transport Canada TDG Regulations, provided the facility holds a valid Certificate of Authorization from a provincial pressure vessel jurisdiction for repair; the facility is registered in accordance with the Transport Canada TDG Regulations to repair the corresponding TC specification; and all repairs are performed using the quality control procedures used to obtain the Certificate of Authorization.
PHMSA also proposes an incidental revision to § 180.413(b) to except facilities in Canada that perform a repair in accordance with the proposed § 180.413(a)(1)(iii) from the requirement that each repair of a cargo tank involving welding on the shell or head must be certified by a Registered Inspector. The Transport Canada TDG Regulations provide requirements for the oversight of welding repairs and do not use the term “Registered Inspector.”
These proposed provisions would not place any additional financial or reporting burden on U.S. companies. Rather, the enhanced regulatory reciprocity between the United States and Canada as a result of these provisions would provide the companies with additional flexibility and cost savings due to necessary opportunities for obtaining repairs to DOT specification cargo tanks in Canada.
See the review of § 107.502 for the discussion of a related proposal.
Section 180.605 prescribes requirements for the qualification of portable tanks. Consistent with the UN Model Regulations, PHMSA proposes an amendment to paragraph (g)(1) to require as a part of internal and external examination that the wall thickness must be verified by appropriate measurement if this inspection indicates a reduction of wall thickness. This proposed amendment would require the inspector to verify that the shell thickness is equal to or greater than the minimum shell thickness indicated on the portable tanks metal plate (see § 178.274(i)(1)).
This proposed rule is published under the statutory authority of Federal hazardous materials transportation law (49 U.S.C. 5101
Harmonization serves to facilitate international commerce, while also promoting the safety of people, property, and the environment by reducing the potential for confusion and misunderstanding that could result if shippers and transporters were required to comply with two or more conflicting sets of regulatory requirements. While the intent of this rulemaking is to align the HMR with international standards, we review and consider each amendment based on its own merit, on its overall impact on transportation safety, and on the economic implications associated with its adoption into the HMR. Our goal is to harmonize internationally without sacrificing the current HMR level of safety or imposing undue burdens on the regulated community. Thus, as explained in the corresponding sections above, we are not proposing harmonization with certain specific provisions of the UN Model Regulations, the IMDG Code, and the ICAO Technical Instructions. Moreover, we are maintaining a number of current exceptions for domestic transportation that should minimize the compliance burden on the regulated community. Additionally, the following external agencies were consulted in the development of this rule: Federal Aviation Administration, Federal Motor Carrier Safety Administration, Federal Railroad Administration, U.S. Coast Guard.
Section 49 U.S.C. 5120(b) of Federal hazmat law authorizes the Secretary to ensure that, to the extent practicable, regulations governing the transportation of hazardous materials in commerce are consistent with standards adopted by international authorities. This rule proposes to amend the HMR to maintain alignment with international standards by incorporating various amendments to facilitate the transport of hazardous material in international commerce. To this end, as discussed in detail above, PHMSA proposes to incorporate changes into the HMR based on the 19th Revised Edition of the UN Model Regulations, Amendment 38-16 to the IMDG Code, and the 2017-2018 Edition of the ICAO Technical Instructions, which become effective January 1, 2017. The large volume of hazardous materials transported in international commerce warrants the harmonization of domestic and international requirements to the greatest extent possible.
This notice is not considered a significant regulatory action under section 3(f) of Executive Order 12866 (“Regulatory Planning and Review”) and, therefore, was not reviewed by the Office of Management and Budget. This notice is not considered a significant rule under the Regulatory Policies and Procedures of the Department of Transportation (44 FR 11034). Additionally, Executive Order 13563 (“Improving Regulation and Regulatory Review”) supplements and reaffirms Executive Order 12866, stressing that, to the extent permitted by law, an agency rulemaking action must be based on benefits that justify its costs, impose the least burden, consider cumulative burdens, maximize benefits, use performance objectives, and assess available alternatives.
For estimating benefits of this proposed rule, we follow a nearly identical approach, while acknowledging there is an inherent imprecision of benefits, and update the data and assumptions where possible. Unlike in the last regulatory evaluation, 2012 Commodity Flow Survey (CFS) data on hazardous materials is now available. According to the 2012 CFS, $13,852,143 million worth of commodities were transported in the U.S. in 2012, of which $2,334,425 million worth were hazardous (or 16.9 percent).
However, we acknowledge that the estimated 16.9 percent proportion of total shipment values classed as hazardous materials may have had a high-side bias due to the variety of different classes of products classified as hazardous. The percentage of shipments properly classified as hazardous—particularly for medicinal/dental/pharmaceutical products—is likely lower, which for the purpose of this analysis we assume to be 10 percent.
We update our estimate of value of hazardous materials involved in international trade by using U.S. trade in goods seasonally adjusted, Census-based total gross imports, and gross exports in the fuels and lubricants, chemicals, and medicinal/dental/pharmaceutical products industries for 2015, which is the most recent year available.
• Gross imports: $451.8 billion (rounded).
○ Fuels and lubricants: $198.217 billion.
○ Chemicals: $73.304 billion.
○ Medicinal/dental/pharmaceutical products: $180.280 billion.
• Gross exports: $281.6 billion (rounded).
○ Fuels and lubricants: $115.013 billion.
○ Chemicals: $111.492 billion.
○ Medicinal/dental/pharmaceutical products: $55.046 billion.
• Gross imports plus gross exports: $733.4 billion.
Multiplying this $733.4 billion figure by the estimated proportion of annual trade in these three industries that are hazardous products (10 percent) by the average hazard communication cost per dollar of hazardous materials produced in the United States ($0.001) results in an estimate of benefits from general harmonization of about $73.3 million annually, rounded.
If the HMR are not harmonized with international standards, we estimate that it will cost U.S. companies an additional $73.3 million per year to comply with both the domestic and international standards. Harmonizing the HMR with the international
Please see the RIA for this rulemaking—a copy of which has been placed in the docket—for detailed analysis of the costs of various amendments proposed in this NPRM. We provide below a summary of cost estimates for several of the larger cost proposals.
It is unknown how many individuals and firms involved in shipping hazardous materials will purchase copies of these international standards as a result of finalizing this rulemaking. We take a conservative approach to estimating such a figure by using as a proxy the number of shippers, carriers, or other offerors or transporters of hazardous materials in commerce with a PHMSA registration expiring before 2019. Currently, PHMSA's registration database indicates 38,070 registrants as of March 18, 2016.
If we assume (for conservative estimation purposes) that all registrants will purchase copies of the ICAO and IMDG publications, this indicates an estimated cost of $19.3 million (rounded, $508.70 cost of ICAO and IMDG publications × 38,070 registrants). However, we further assume that the two publications included in the $19.3 cost (ICAO Technical Instructions (for air) and IMDG Code (by vessel)) will not apply to such registrants who indicated that they offer or transport in commerce hazardous materials only via highway. Therefore, costs for the 31,765 highway-only registrants would be zero. To counterbalance a registrant purchasing more than one copy, we conservatively assume all other registrants—while acknowledging that, in fact, some will purchase both standards copies and some will purchase none—will purchase updated copies of all standards publications listed here, indicating a rounded cost of $3.2 million ($508.70 × 6,305 registrants [38,070 total registrants − 31,765 highway-only registrants]).
All of the ISO standards incorporated will not be purchased by the majority of shippers and carriers and, thus, will likely only impact a small subset of the regulated community. Further, we assume that many companies will purchase multiple copies of the ISO codes, rather than only one copy. Manufacturers of pressure receptacles impacted by the ISO codes are included in the North American Industry Classification System (NAICS) 332420 “Metal Tank (Heavy Gauge) Manufacturing,” which includes cylinders, and NAICS 332911 “Industrial Valve Manufacturing,” or more generally in NAICS 332, “Fabricated Metal Product Manufacturing.” Users of pressure receptacles impacted by the ISO codes are included in NAICS 325120 “Industrial Gas Manufacturing,” or more generally in NAICS 325 “Chemical Manufacturing.” Testers and requalifiers of pressure receptacles are included in NAICS 541380 “Testing Laboratories,” or more generally in NAICS 541 “Professional, Scientific, and Technical Services.” The more conservative, all-encompassing three-digit NAICS industries are used to estimate impacted entities, as each entity may purchase more than one copy of a publication. The PHMSA registration database has 834 registrants in NAICS 332; 3,335 registrants in NAICS 325; and 415 registrants in NAICS 541, for a total of 4,584 impacted registrants. It costs each impacted registrant $1,853 to purchase the ISO standards, or $8.5 million total (rounded, 4,584 impacted registrants × $1,853 cost per registrant).
It will cost $3.2 million to purchase the ICAO and IMDG publications and $8.5 million to purchasing the ISO publications, giving a total one-time cost of $11.7 million. We do not believe we have sufficient data to estimate the precise number of registrants. However, we use one copy per impacted registrant as a reasonably conservative estimate on costs of the proposed rulemaking. It should also be noted that several of the companies purchasing the international standards may serve international markets and would have purchased these publications even in the absence of this rulemaking. Therefore, costs due to this proposed rule are likely lower than these estimates.
PHMSA anticipates that incorporating a new standard lithium battery mark across all modes will provide consistent hazard communication, reduce training costs, and facilitate intermodal movements. Expanding the scope of packages requiring application of the new lithium battery mark for small shipments of lithium batteries will provide benefits pertaining to better identification of lithium battery shipments, but it will likely involve some amount of increased compliance cost. As with the proposed labeling
PHMSA anticipates that eliminating additional document requirements for shipments of small lithium batteries will likely provide economic benefits and cost savings to shippers.
However, PHMSA anticipates the provision increasing the number of packages containing lithium batteries installed in equipment that have to be marked with the lithium battery mark will increase compliance costs. The proposals in this NPRM would apply the lithium battery mark to an expanded number of lithium batteries installed in equipment (LBIIE) packages. Currently packages that contain “no more than four lithium cells or two lithium batteries installed in equipment” are not subject to marking requirements regardless of how many packages are in a single shipment. In this NPRM, PHMSA proposes to require each package that contains lithium batteries installed in equipment to display the lithium battery marking when there are more than two packages in the consignment.
We assume that U.S. manufacturers of certain equipment containing lithium batteries and wholesalers of LBIIE that supply retailers with consignments containing more than two packages of LBIIE will be most impacted by the proposed provision.
The total domestic manufacturer and wholesaler marking costs as illustrated in the RIA in the docket for this rulemaking approximates the upper bound annual cost of the provision to be about $4.9 million ($838,456 + $7,665 + $4.0 million).
Based on the discussions of benefits and costs provided above, PHMSA estimates the net benefit associated with the rulemaking to be $63.2 million-69 million in the first year after publication and $70 million-75.8 million in the second year after publication. Please see the complete RIA for a more detailed analysis of the costs and benefits of this proposed rule.
This proposed rule has been analyzed in accordance with the principles and criteria contained in Executive Order 13132 (“Federalism”). It preempts State, local, and Indian tribe requirements but does not propose any regulation that has substantial direct effects on the States, the relationship between the national government and the States, or the distribution of power and responsibilities among the various levels of government. Therefore, the consultation and funding requirements of Executive Order 13132 do not apply.
The Federal hazmat law, 49 U.S.C. 5101-5128, contains an express preemption provision (49 U.S.C. 5125(b)) that preempts State, local, and Indian tribe requirements on certain covered subjects, as follows:
(1) The designation, description, and classification of hazardous material;
(2) The packing, repacking, handling, labeling, marking, and placarding of hazardous material;
(3) The preparation, execution, and use of shipping documents related to hazardous material and requirements related to the number, contents, and placement of those documents;
(4) The written notification, recording, and reporting of the unintentional release in transportation of hazardous material; and
(5) The design, manufacture, fabrication, inspection, marking, maintenance, recondition, repair, or testing of a packaging or container represented, marked, certified, or sold as qualified for use in transporting hazardous material in commerce.
This proposed rule addresses covered subject items (1), (2), (3), (4), and (5) above and preempts State, local, and Indian tribe requirements not meeting the “substantively the same” standard. This proposed rule is necessary to incorporate changes adopted in international standards, effective January 1, 2017. If the proposed changes are not adopted in the HMR, U.S. companies—including numerous small entities competing in foreign markets—would be at an economic disadvantage because of their need to comply with a dual system of regulations. The changes in this proposed rulemaking are intended to avoid this result. Federal hazmat law provides at 49 U.S.C. 5125(b)(2) that, if DOT issues a regulation concerning any of the covered subjects, DOT must determine and publish in the
This proposed rule was analyzed in accordance with the principles and criteria contained in Executive Order 13175 (“Consultation and Coordination with Indian Tribal Governments”). Because this proposed rule does not have tribal implications, does not impose substantial direct compliance costs, and is required by statute, the funding and consultation requirements of Executive Order 13175 do not apply.
The Regulatory Flexibility Act (5 U.S.C. 601
Many companies will realize economic benefits as a result of these amendments. Additionally, the changes effected by this NPRM will relieve U.S. companies, including small entities competing in foreign markets, from the burden of complying with a dual system of regulations. Therefore, we certify that these amendments will not, if promulgated, have a significant economic impact on a substantial number of small entities.
This proposed rule has been developed in accordance with Executive Order 13272 (“Proper Consideration of Small Entities in Agency Rulemaking”) and DOT's procedures and policies to promote compliance with the Regulatory Flexibility Act to ensure that potential impacts of draft rules on small entities are properly considered.
PHMSA currently has approved information collections under Office of Management and Budget (OMB) Control Number 2137-0557, “Approvals for Hazardous Materials,” and OMB Control Number 2137-0034, “Hazardous Materials Shipping Papers & Emergency Response Information.” We anticipate that this proposed rule will result in an increase in the annual burden for OMB Control Number 2137-0034 due to an increase in the number of applications for modifications to existing holders of DOT-issued RINs. In this NPRM, PHMSA proposes to amend § 107.805(f)(2) to allow RIN holders to submit an application containing all the required information prescribed in § 107.705(a); identifying the TC, CTC, CRC, or BTC specification cylinder(s) or tube(s) to be inspected; certifying the requalifier will operate in compliance with the applicable TDG Regulations; and certifying the persons performing requalification have been trained and have the information contained in the TDG Regulations. This application would be in addition to any existing application and burden encountered during the initial RIN application.
We anticipate this proposed rule will result in a decrease in the annual burden and costs of OMB Control Number 2137-0034. This burden and cost decrease is primarily attributable to the proposed removal of the alternative document currently required for lithium cells or batteries offered in accordance with § 173.185(c). Additional increased burdens and costs to OMB Control Number 2137-0034 in this proposed rule are attributable to a new proposed indication on shipping papers that a shipment of prototype or low production run lithium batteries or cells is in accordance with § 173.185(e)(7) and the proposed addition of new marine pollutant entries.
This rulemaking identifies revised information collection requests that PHMSA will submit to OMB for approval based on the requirements in this NPRM. PHMSA has developed burden estimates to reflect changes in this NPRM and estimates the information collection and recordkeeping burdens in this rule are as follows:
Under the Paperwork Reduction Act of 1995, no person is required to respond to an information collection unless it has been approved by OMB and displays a valid OMB control number. Section 1320.8(d) of 5 CFR requires that PHMSA provide interested members of the public and affected agencies an opportunity to comment on information and recordkeeping requests. PHMSA specifically solicits comment on the information collection and recordkeeping burdens associated with developing, implementing, and maintaining these proposed requirements. Address written comments to the Dockets Unit as identified in the
A regulation identifier number (RIN) is assigned to each regulatory action listed in the Unified Agenda of Federal Regulations. The Regulatory Information Service Center publishes the Unified Agenda in April and October of each year. The RIN contained in the heading of this document can be used to cross-reference this action with the Unified Agenda.
This proposed rule does not impose unfunded mandates under the Unfunded Mandates Reform Act of 1995. It does not result in costs of $141.3 million or more, adjusted for inflation, to either State, local, or tribal governments, in the aggregate, or to the private sector in any one year, and is the least burdensome alternative that achieves the objective of the rule.
The National Environmental Policy Act of 1969, 42 U.S.C. 4321-4375, requires that Federal agencies analyze proposed actions to determine whether the action will have a significant impact on the human environment. The Council on Environmental Quality (CEQ) regulations that implement NEPA (40 CFR parts 1500 through 1508) require Federal agencies to conduct an environmental review considering (1) the need for the proposed action, (2) alternatives to the proposed action, (3) probable environmental impacts of the proposed action and alternatives, and (4) the agencies and persons consulted during the consideration process.
This NPRM would amend the Hazardous Materials Regulations (HMR; 49 CFR parts 171 through 180) to maintain consistency with international standards by incorporating the 19th Revised Edition of the UN Recommendations on the Transport of Dangerous Goods—Model Regulations, Amendment 38-16 to the IMDG Code, the 2017-2018 ICAO Technical Instructions, and Canada's newest amendments to TDG Regulations.
This action is necessary to incorporate changes adopted in the IMDG Code, the ICAO Technical Instructions, and the UN Model Regulations, effective January 1, 2017. If the changes in this proposed rule are not adopted in the HMR by this effective date, U.S. companies—including numerous small entities
The intended effect of this action is to harmonize the HMR with international transport standards and requirements to the extent practicable in accordance with Federal hazmat law (see 49 U.S.C. 5120). When considering the adoption of international standards under the HMR, PHMSA reviews and evaluates each amendment on its own merit, on its overall impact on transportation safety, and on the economic implications associated with its adoption. Our goal is to harmonize internationally without diminishing the level of safety currently provided by the HMR or imposing undue burdens on the regulated public. PHMSA has provided a brief summary of each revision, the justification for the revision, and a preliminary estimate of economic impact.
In proposing this rulemaking, PHMSA is considering the following alternatives:
If PHMSA were to select the No Action Alternative, current regulations would remain in place and no new provisions would be added. However, efficiencies gained through harmonization in updates to transport standards, lists of regulated substances, definitions, packagings, stowage requirements/codes, flexibilities allowed, enhanced markings, segregation requirements, etc., would not be realized. Foregone efficiencies in the No Action Alternative include freeing up limited resources to concentrate on vessel transport hazard communication (hazcom) issues of potentially much greater environmental impact. Adopting the No Action Alternative would result in a lost opportunity for reducing environmental and safety-related incidents.
Greenhouse gas emissions would remain the same under the No Action Alternative.
This alternative is the current proposal as it appears in this NPRM, applying to transport of hazardous materials by various transport modes (highway, rail, vessel, and aircraft). The proposed amendments included in this alternative are more fully addressed in the preamble and regulatory text sections of this NPRM. However, they generally include:
(1) Updates to references to various international hazardous materials transport standards;
(2) Amendments to the Hazardous Materials Table to include four new Division 4.1 entries for polymerizing substances and to add into the HMR defining criteria, authorized packagings, and safety requirements;
(3) Amendments to add, revise, or remove certain proper shipping names, packing groups, special provisions, packaging authorizations, bulk packaging requirements, and vessel stowage requirements;
(4) Changes to add the following substances to the list of marine pollutants in appendix B to § 172.101: Hexanes; Hypochlorite solutions; Isoprene, stabilized; N-Methylaniline; Methylcyclohexane; and Tripropylene;
(5) Changes throughout the part 173 packaging requirements to authorize more flexibility when choosing packages for hazardous materials;
(6) Various amendments to packaging requirements for the vessel transportation of water-reactive substances;
(7) Revisions to hazard communication requirements for shipments of lithium batteries consistent with changes adopted in the 19th Revised Edition of the UN Model Regulations; and
(8) Amendments to the HMR resulting from coordination with Canada under the U.S.-Canada Regulatory Cooperation Council (RCC).
If PHMSA were to select the No Action Alternative, current regulations would remain in place and no new provisions would be added. However, efficiencies gained through harmonization in updates to transport standards, lists of regulated substances, definitions, packagings, stowage requirements/codes, flexibilities allowed, enhanced markings, segregation requirements, etc., would not be realized. Foregone efficiencies in the No Action Alternative include freeing up limited resources to concentrate on vessel transport hazcom issues of potentially much greater environmental impact.
Additionally, the Preferred Alternative encompasses enhanced and clarified regulatory requirements, which would result in increased compliance and a decreased number of environmental and safety incidents. Not adopting the proposed environmental and safety requirements in the NPRM under the No Action Alternative would result in a lost opportunity for reducing environmental and safety-related incidents.
Greenhouse gas emissions would remain the same under the No Action Alternative.
If PHMSA selects the provisions as proposed in this NPRM, safety and environmental risks would be reduced and that protections to human health and environmental resources would be increased. Potential environmental impacts of each proposed amendment in the preferred alternative are discussed as follows:
1.
This proposed amendment, which will increase standardization and consistency of regulations, will result in greater protection of human health and the environment. Consistency between U.S. and international regulations enhances the safety and environmental protection of international hazardous materials transportation through better understanding of the regulations, an increased level of industry compliance, the smooth flow of hazardous materials from their points of origin to their points of destination, and consistent emergency response in the event of a hazardous materials incident. The HMR authorize shipments prepared in accordance with the ICAO Technical Instructions and by motor vehicle either before or after being transported by aircraft. Similarly, the HMR authorize shipments prepared in accordance with the IMDG Code if all or part of the transportation is by vessel. The authorizations to use the ICAO Technical Instructions and the IMDG Code are subject to certain conditions and limitations outlined in part 171 subpart C.
Harmonization will result in more targeted and effective training and
Greenhouse gas emissions would remain the same under this proposed amendment.
2.
This proposed amendment, which will increase standardization and consistency of regulations, will result in greater protection of human health and the environment. Consistency between U.S. and international regulations enhances the safety and environmental protection of international hazardous materials transportation through better understanding of the regulations, an increased level of industry compliance, the smooth flow of hazardous materials from their points of origin to their points of destination, and consistent emergency response in the event of a hazardous materials incident. New and revised entries to the HMT reflect emerging technologies and a need to better describe or differentiate between existing entries. These proposed changes mirror changes in the Dangerous Goods List of the 19th Revised Edition of the UN Model Regulations, the 2017-2018 ICAO Technical Instructions, and the Amendment 38-16 to the IMDG Code. It is extremely important for the domestic HMR to mirror these international standards regarding the entries in the HMT to allow for consistent naming conventions across modes and international borders.
Harmonization will result in more targeted and effective training and thereby enhanced environmental protection. This proposed amendment will eliminate inconsistent hazardous materials regulations, which hamper compliance training efforts. For ease of compliance with appropriate regulations, international carriers engaged in the transportation of hazardous materials by vessel generally elect to comply with the IMDG Code. Consistency between these international regulations and the HMR allows shippers and carriers to train their hazmat employees in a single set of requirements for classification, packaging, hazard communication, handling, stowage, etc., thereby minimizing the possibility of improperly preparing and transporting a shipment of hazardous materials because of differences between domestic and international regulations.
Inclusion of entries in the HMT reflects a degree of danger associated with a particular material and identifies appropriate packaging. This proposed change provides a level of consistency for all articles specifically listed in the HMT, without diminishing environmental protection and safety.
Greenhouse gas emissions would remain the same under this proposed amendment.
3.
This proposed amendment, which will increase standardization and consistency of regulations, will result in greater protection of human health and the environment. Consistency between U.S. and international regulations enhances the safety and environmental protection of international hazardous materials transportation through better understanding of the regulations, an increased level of industry compliance, the smooth flow of hazardous materials from their points of origin to their points of destination, and consistent emergency response in the event of a hazardous materials incident. New and revised entries to the HMT reflect emerging technologies and a need to better describe or differentiate between existing entries. These proposed changes mirror changes in the Dangerous Goods List of the 19th Revised Edition of the UN Model Regulations, the 2017-2018 ICAO Technical Instructions, and the Amendment 38-16 to the IMDG Code. It is extremely important for the domestic HMR to mirror these international standards regarding the entries in the HMT to allow for consistent naming conventions across modes and international borders.
Harmonization will result in more targeted and effective training and thereby enhanced environmental protection. This proposed amendment will eliminate inconsistent hazardous materials regulations, which hamper compliance training efforts. For ease of compliance with appropriate regulations, international carriers engaged in the transportation of hazardous materials by vessel generally elect to comply with the IMDG Code. Consistency between these international regulations and the HMR allows shippers and carriers to train their hazmat employees in a single set of requirements for classification, packaging, hazard communication, handling, stowage, etc., thereby minimizing the possibility of improperly preparing and transporting a shipment of hazardous materials because of differences between domestic and international regulations.
Inclusion of entries in the HMT reflects a degree of danger associated with a particular material and identifies appropriate packaging. This proposed change provides a level of consistency for all articles specifically listed in the HMT, without diminishing environmental protection and safety.
Greenhouse gas emissions would remain the same under this proposed amendment.
4.
This proposed amendment, which will increase standardization and
Greenhouse gas emissions would remain the same under this proposed amendment.
5.
These proposed amendments permit additional flexibility for authorized packages without compromising environmental protection or safety. Manufacturing and performance standards for gas pressure receptacles strengthen the packaging without being overly prescriptive. Increased flexibility will also add to environmental protection by increasing the ease of regulatory compliance.
Harmonization will result in more targeted and effective training and thereby enhanced environmental protection. This proposed amendment will eliminate inconsistent hazardous materials regulations, which hamper compliance training efforts. Consistency between these international regulations and the HMR allows shippers and carriers to train their hazmat employees in a single set of requirements for classification, packaging, hazard communication, handling, stowage, etc., thereby minimizing the possibility of improperly preparing and transporting a shipment of hazardous materials because of differences between domestic and international regulations.
Greenhouse gas emissions would remain the same under this proposed amendment.
6.
The proposed amendment will reduce the risk of fire on board cargo vessels carrying hazardous materials that can react dangerously with the ship's available water and carbon dioxide fire extinguishing systems. PHMSA proposes to amend the packaging requirements for vessel transportation of hazardous materials that react with water or moisture to generate excessive heat or release toxic or flammable gases. Common causes for water entering into the container are: Water entering through ventilation or structural flaws in the container; water entering into the containers placed on deck or in the hold in heavy seas; and water entering into the cargo space upon a ship collision or leak. If water has already entered the container, the packaging is the only protection from the fire. In this NPRM, PHMSA proposes to strengthen the ability of these packages transporting water-reactive substances. This proposed amendment will allow for a net increase in environmental protection and safety by keeping reactive substances in their packages, thus preventing release and damage to human health and the natural environment.
Harmonization will result in more targeted and effective training and thereby enhanced environmental protection. This proposed amendment will eliminate inconsistent hazardous materials regulations, which hamper compliance training efforts. For ease of compliance with appropriate regulations, international carriers engaged in the transportation of hazardous materials by vessel generally elect to comply with the IMDG Code. Consistency between these international regulations and the HMR allows shippers and carriers to train their hazmat employees in a single set of requirements for classification, packaging, hazard communication, handling, stowage, etc., thereby minimizing the possibility of improperly preparing and transporting a shipment of hazardous materials because of differences between domestic and international regulations.
Greenhouse gas emissions would remain the same under this proposed amendment.
7.
This proposed amendment, which will provide for enhanced hazard communication, will result in greater protection of human health and the environment by increasing awareness and preparedness.
Greenhouse gas emissions would remain the same under this proposed amendment.
8.
This proposed amendment, which will increase standardization and consistency of regulations, will result in greater protection of human health and the environment. Consistency between U.S. and international regulations enhances the safety and environmental protection of international hazardous materials transportation through better understanding of the regulations, an increased level of industry compliance, the smooth flow of hazardous materials from their points of origin to their
The proposed action is consistent with concurrent actions by Transport Canada to amend the TDG Regulations.
Greenhouse gas emissions would remain the same under this proposed amendment.
This NPRM represents PHMSA's first action in the U.S. for this program area. PHMSA has coordinated with the U.S. Federal Aviation Administration, the Federal Motor Carrier Safety Administration, the Federal Railroad Administration, and the U.S. Coast Guard, in the development of this proposed rule. PHMSA will consider the views expressed in comments to the NPRM submitted by members of the public, state and local governments, and industry.
The provisions of this proposed rule build on current regulatory requirements to enhance the transportation safety and security of shipments of hazardous materials transported by highway, rail, aircraft, and vessel, thereby reducing the risks of an accidental or intentional release of hazardous materials and consequent environmental damage. PHMSA concludes that the net environmental impact will be positive and that there are no significant environmental impacts associated with this proposed rule.
PHMSA welcomes any views, data, or information related to environmental impacts that may result if the proposed requirements are adopted, as well as possible alternatives and their environmental impacts.
Anyone is able to search the electronic form of any written communications and comments received into any of our dockets by the name of the individual submitting the document (or signing the document, if submitted on behalf of an association, business, labor union, etc.). You may review DOT's complete Privacy Act Statement in the
Under Executive Order 13609 (“Promoting International Regulatory Cooperation”), agencies must consider whether the impacts associated with significant variations between domestic and international regulatory approaches are unnecessary or may impair the ability of American business to export and compete internationally. In meeting shared challenges involving health, safety, labor, security, environmental, and other issues, international regulatory cooperation can identify approaches that are at least as protective as those that are or would be adopted in the absence of such cooperation. International regulatory cooperation can also reduce, eliminate, or prevent unnecessary differences in regulatory requirements.
Similarly, the Trade Agreements Act of 1979 (Pub. L. 96-39), as amended by the Uruguay Round Agreements Act (Pub. L. 103-465), prohibits Federal agencies from establishing any standards or engaging in related activities that create unnecessary obstacles to the foreign commerce of the United States. For purposes of these requirements, Federal agencies may participate in the establishment of international standards, so long as the standards have a legitimate domestic objective, such as providing for safety, and do not operate to exclude imports that meet this objective. The statute also requires consideration of international standards and, where appropriate, that they be the basis for U.S. standards.
PHMSA participates in the establishment of international standards to protect the safety of the American public. PHMSA has assessed the effects of the proposed rule and determined that it does not cause unnecessary obstacles to foreign trade. In fact, the rule is designed to facilitate international trade. Accordingly, this rulemaking is consistent with Executive Order 13609 and PHMSA's obligations under the Trade Agreement Act, as amended.
The National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) directs Federal agencies to use voluntary consensus standards in their regulatory activities unless doing so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (
Administrative practice and procedure, Hazardous materials transportation, Packaging and containers, Penalties, Reporting and recordkeeping requirements.
Exports, Hazardous materials transportation, Hazardous waste, Imports, Incorporation by reference, Reporting and recordkeeping requirements.
Education, Hazardous materials transportation, Hazardous waste, Incorporation by reference, Labeling, Markings, Packaging and containers, Reporting and recordkeeping requirements.
Hazardous materials transportation, Incorporation by reference, Packaging and containers, Radioactive materials, Reporting and recordkeeping requirements, Uranium.
Air carriers, Hazardous materials transportation, Radioactive materials, Reporting and recordkeeping requirements.
Maritime carriers, Hazardous materials transportation, Incorporation by reference, Radioactive materials, Reporting and recordkeeping requirements.
Hazardous materials transportation, Incorporation by reference, Motor vehicle safety, Packaging and containers, Reporting and recordkeeping requirements.
Hazardous materials transportation, Motor carriers, Motor vehicle safety, Packaging and containers, Railroad safety, Reporting and recordkeeping requirements.
In consideration of the foregoing, PHMSA proposes to amend 49 CFR chapter I as follows:
49 U.S.C. 5101-5128, 44701; Pub. L. 101-410 section 4 (28 U.S.C. 2461note); Pub. L. 104-121 sections 212-213; Pub. L. 104-134 section 31001; Pub. L. 112-141 section 33006, 33010; 49 CFR 1.81 and 1.97.
(b) No person may engage in the manufacture, assembly, certification, inspection or repair of a cargo tank or cargo tank motor vehicle manufactured under the terms of a DOT specification under subchapter C of this chapter or a special permit issued under this part unless the person is registered with the Department in accordance with the provisions of this subpart. A person employed as an inspector or design certifying engineer is considered to be registered if the person's employer is registered. The requirements of this paragraph do not apply to a person engaged in the repair of a DOT specification cargo tank used in the transportation of hazardous materials in the United States in accordance with § 180.413(a)(1)(iii) of this chapter.
(a) * * *
(2) A person who seeks approval to engage in the requalification (
(a)
(c) * * *
(2) The types of DOT specification or special permit cylinders, UN pressure receptacles, or TC, CTC, CRC, or BTC specification cylinders or tubes that will be inspected, tested, repaired, or rebuilt at the facility;
(d)
(f)
(1) A person who only performs inspections in accordance with § 180.209(g) of this chapter provided the application contains the following, in addition to the information prescribed in § 107.705(a): Identifies the DOT specification/special permit cylinders to be inspected; certifies the requalifier will operate in compliance with the applicable requirements of subchapter C of this chapter; certifies the persons performing inspections have been trained and have the information contained in each applicable CGA pamphlet incorporated by reference in § 171.7 of this chapter applicable to the requalifiers' activities; and includes the signature of the person making the certification and the date on which it was signed. Each person must comply with the applicable requirements in this subpart. In addition, the procedural requirements in subpart H of this part apply to the filing, processing and termination of an approval issued under this subpart; or
(2) A person holding a DOT-issued RIN to perform the requalification (inspect, test, certify), repair, or rebuild of DOT specification cylinders, that wishes to perform any of these actions on corresponding TC, CTC, CRC, or BTC cylinders or tubes may submit an application that, in addition to the information prescribed in § 107.705(a): Identifies the TC, CTC, CRC, or BTC specification cylinder(s) or tube(s) to be inspected; certifies the requalifier will operate in compliance with the applicable TDG Regulations; certifies the persons performing requalification have been trained in the functions applicable to the requalifiers' activities; and includes the signature of the person making the certification and the date on which it was signed. In addition, the procedural requirements in subpart H of this part apply to the filing, processing and termination of an approval issued under this subpart.
(3) A person holding a certificate of registration issued by Transport Canada in accordance with the TDG Regulations to perform the requalification (inspect, test, certify), repair, or rebuild of a TC, CTC, CRC, or BTC cylinder who performs any of these actions on corresponding DOT specification cylinders.
49 U.S.C. 5101-5128, 44701; Pub. L. 101-410 section 4 (28 U.S.C. 2461 note); Pub. L. 104-134, section 31001; 49 CFR 1.81 and 1.97.
(h) * * *
(1) Specification identifications that include the letters “ICC”, “DOT”, “TC”, “CTC”, “CRC”, “BTC”, “MC”, or “UN”;
The revisions and additions read as follows:
(t)
(1) Technical Instructions for the Safe Transport of Dangerous Goods by Air (ICAO Technical Instructions), 2017-2018 Edition, into §§ 171.8; 171.22; 171.23; 171.24; 172.101; 172.202; 172.401; 172.512; 172.519; 172.602; 173.56; 173.320; 175.10, 175.33; 178.3.
(v)
(1) * * *
(2) International Maritime Dangerous Goods Code (IMDG Code), Incorporating Amendment 38-16 (English Edition), 2016 Edition, into §§ 171.22; 171.23; 171.25; 172.101; 172.202; 172.203 172.401; 172.502; 172.519; 172.602; 173.21; 173.56; 176.2; 176.5; 176.11; 176.27; 176.30; 176.83; 176.84; 176.140; 176.720; 178.3; 178.274.
(w) * * *
(1) ISO 535-1991(E) Paper and board—Determination of water absorptiveness—Cobb method, 1991, into §§ 178.516; 178.707; 178.708.
(2) ISO 1496-1: 1990 (E)—Series 1 freight containers—Specification and testing, Part 1: General cargo containers. Fifth Edition, (August 15, 1990), into § 173.411.
(3) ISO 1496-3(E)—Series 1 freight containers—Specification and testing—Part 3: Tank containers for liquids, gases and pressurized dry bulk, Fourth edition, March 1995, into §§ 178.74; 178.75; 178.274.
(4) ISO 1516:2002(E), Determination of flash/no flash—Closed cup equilibrium method, Third Edition, 2002-03-01, into § 173.120.
(5) ISO 1523:2002(E), Determination of flash point—Closed cup equilibrium method, Third Edition, 2002-03-01, into § 173.120.
(6) ISO 2431-1984(E) Standard Cup Method, 1984, into § 173.121.
(7) ISO 2592:2000(E), Determination of flash and fire points—Cleveland open cup method, Second Edition, 2000-09-15, into § 173.120.
(8) ISO 2719:2002(E), Determination of flash point—Pensky-Martens closed cup method, Third Edition, 2002-11-15, into § 173.120.
(9) ISO 2919:1999(E), Radiation Protection—Sealed radioactive sources—General requirements and classification, (ISO 2919), second edition, February 15, 1999, into § 173.469.
(10) ISO 3036-1975(E) Board—Determination of puncture resistance, 1975, into § 178.708.
(11) ISO 3405:2000(E), Petroleum products—Determination of distillation characteristics at atmospheric pressure, Third Edition, 2000-03-01, into § 173.121.
(12) ISO 3574-1986(E) Cold-reduced carbon steel sheet of commercial and drawing qualities, into § 178.503; part 178, appendix C.
(13) ISO 3679:2004(E), Determination of flash point—Rapid equilibrium closed cup method, Third Edition, 2004-04-01, into § 173.120.
(14) ISO 3680:2004(E), Determination of flash/no flash—Rapid equilibrium closed cup method, Fourth Edition, 2004-04-01, into § 173.120.
(15) ISO 3807-2(E), Cylinders for acetylene—Basic requirements—Part 2: Cylinders with fusible plugs, First edition, March 2000, into §§ 173.303; 178.71.
(16) ISO 3807:2013: Gas cylinders—Acetylene cylinders—Basic requirements and type testing, Second edition, 2013-08-19, into §§ 173.303; 178.71.
(17) ISO 3924:1999(E), Petroleum products—Determination of boiling range distribution—Gas chromatography method, Second Edition, 1999-08-01, into § 173.121.
(18) ISO 4126-1:2004(E): Safety devices for protection against excessive pressure—Part 1: Safety valves, Second edition 2004-02-15, into § 178.274.
(19) ISO 4126-7:2004(E): Safety devices for protection against excessive pressure—Part 7: Common data, First Edition 2004-02-15 into § 178.274.
(20) ISO 4126-7:2004/Cor.1:2006(E): Safety devices for protection against excessive pressure—Part 7: Common data, Technical Corrigendum 1, 2006-11-01, into § 178.274.
(21) ISO 4626:1980(E), Volatile organic liquids—Determination of boiling range of organic solvents used as raw materials, First Edition, 1980-03-01, into § 173.121.
(22) ISO 4706:2008(E), Gas cylinders—Refillable welded steel cylinders—Test pressure 60 bar and below, First Edition, 2008-04-15, Corrected Version, 2008-07-01, into § 178.71.
(23) ISO 6406(E), Gas cylinders—Seamless steel gas cylinders—Periodic inspection and testing, Second edition, February 2005, into § 180.207.
(24) ISO 6892 Metallic materials—Tensile testing, July 15, 1984, First Edition, into § 178.274.
(25) ISO 7225(E), Gas cylinders—Precautionary labels, Second Edition, July 2005, into § 178.71.
(26) ISO 7866(E), Gas cylinders—Refillable seamless aluminum alloy gas cylinders—Design, construction and testing, First edition, June 1999, into § 178.71.
(27) ISO 7866:2012 Gas cylinders—Refillable seamless aluminium alloy gas cylinders—Design, construction and testing, Second edition, 2012-08-21, into § 178.71.
(28) ISO 7866:2012/Cor 1:2014 Gas cylinders—Refillable seamless aluminium alloy gas cylinders—Design, construction and testing, Technical Corrigendum 1, 2014-04-15, into § 178.71.
(29) ISO 8115 Cotton bales—Dimensions and density, 1986 Edition, into § 172.102.
(30) ISO 9809-1:1999(E): Gas cylinders—Refillable seamless steel gas cylinders—Design, construction and testing—Part 1: Quenched and tempered steel cylinders with tensile strength less than 1100 MPa., First edition, June 1999, into §§ 178.37; 178.71; 178.75.
(31) ISO 9809-1:2010(E): Gas cylinders—Refillable seamless steel gas cylinders—Design, construction and testing—Part 1: Quenched and tempered steel cylinders with tensile strength less than 1 100 MPa., Second edition, 2010-04-15, into §§ 178.37; 178.71; 178.75.
(32) ISO 9809-2:2000(E): Gas cylinders—Refillable seamless steel gas cylinders—Design, construction and testing—Part 2: Quenched and tempered steel cylinders with tensile strength greater than or equal to 1 100 MPa., First edition, June 2000, into §§ 178.71; 178.75.
(33) ISO 9809-2:2010(E): Gas cylinders—Refillable seamless steel gas cylinders—Design, construction and testing—Part 2: Quenched and tempered steel cylinders with tensile strength greater than or equal to 1100 MPa., Second edition, 2010-04-15, into §§ 178.71; 178.75.
(34) ISO 9809-3:2000(E): Gas cylinders—Refillable seamless steel gas cylinders—Design, construction and testing—Part 3: Normalized steel cylinders, First edition, December 2000, into §§ 178.71; 178.75.
(35) ISO 9809-3:2010(E): Gas cylinders—Refillable seamless steel gas cylinders—Design, construction and testing—Part 3: Normalized steel cylinders, Second edition, 2010-04-15, into §§ 178.71; 178.75.
(36) ISO 9809-4:2014 Gas cylinders—Refillable seamless steel gas cylinders—
(37) ISO 9978:1992(E)—Radiation protection—Sealed radioactive sources—Leakage test methods. First Edition, (February 15, 1992), into § 173.469.
(38) ISO 10156:2010(E): Gases and gas mixtures—Determination of fire potential and oxidizing ability for the selection of cylinder valve outlets, Third edition, 2010-04-01, into § 173.115.
(39) ISO 10156:2010/Cor.1:2010(E): Gases and gas mixtures—Determination of fire potential and oxidizing ability for the selection of cylinder valve outlets, Technical Corrigendum 1, 2010-09-01, into § 173.115.
(40) ISO 10297:1999(E), Gas cylinders—Refillable gas cylinder valves—Specification and type testing, First Edition, 1995-05-01, into §§ 173.301b; 178.71.
(41) ISO 10297:2006(E), Transportable gas cylinders—Cylinder valves—Specification and type testing, Second Edition, 2006-01-15, into §§ 173.301b; 178.71.
(42) ISO 10297:2014 Gas cylinders—Cylinder valves—Specification and type testing, Third Edition, 20014-07-16, into §§ 173.301b; 178.71.
(43) ISO 10461:2005(E), Gas cylinders—Seamless aluminum-alloy gas cylinders—Periodic inspection and testing, Second Edition, 2005-02-15 and Amendment 1, 2006-07-15, into § 180.207.
(44) ISO 10462 (E), Gas cylinders—Transportable cylinders for dissolved acetylene—Periodic inspection and maintenance, Second edition, February 2005, into § 180.207.
(45) ISO 10462:2013 Gas cylinders—Acetylene cylinders—Periodic inspection and maintenance, Third edition, 2013-12-05, into § 180.207.
(46) ISO 10692-2:2001(E), Gas cylinders—Gas cylinder valve connections for use in the micro-electronics industry—Part 2: Specification and type testing for valve to cylinder connections, First Edition, 2001-08-01, into §§ 173.40; 173.302c.
(47) ISO 11114-1:2012(E), Gas cylinders—Compatibility of cylinder and valve materials with gas contents—Part 1: Metallic materials, Second edition, 2012-03-15, into §§ 172.102; 173.301b; 178.71.
(48) ISO 11114-2:2013 Gas cylinders—Compatibility of cylinder and valve materials with gas contents—Part 2: Non-metallic materials, Second edition, 2013-03-21, into §§ 173.301b; 178.71.
(49) ISO 11117:1998(E): Gas cylinders—Valve protection caps and valve guards for industrial and medical gas cylinders.—Design, construction and tests, First edition, 1998-08-01, into § 173.301b.
(50) ISO 11117:2008(E): Gas cylinders—Valve protection caps and valve guards—Design, construction and tests, Second edition, 2008-09-01, into § 173.301b.
(51) ISO 11117:2008/Cor.1:2009(E): Gas cylinders—Valve protection caps and valve guards—Design, construction and tests, Technical Corrigendum 1, 2009-05-01, into § 173.301b.
(52) ISO 11118(E), Gas cylinders—Non-refillable metallic gas cylinders—Specification and test methods, First edition, October 1999, into § 178.71.
(53) ISO 11119-1(E), Gas cylinders—Gas cylinders of composite construction—Specification and test methods—Part 1: Hoop-wrapped composite gas cylinders, First edition, May 2002, into § 178.71.
(54) ISO 11119-1:2012 Gas cylinders—Refillable composite gas cylinders and tubes—Design, construction and testing—Part 1: Hoop wrapped fibre reinforced composite gas cylinders and tubes up to 450 l, Second edition, 2012-07-25, into § 178.71.
(55) ISO 11119-2(E), Gas cylinders—Gas cylinders of composite construction—Specification and test methods—Part 2: Fully wrapped fibre reinforced composite gas cylinders with load-sharing metal liners, First edition, May 2002, into § 178.71.
(56) ISO 11119-2:2012 Gas cylinders—Refillable composite gas cylinders and tubes—Design, construction and testing—Part 2: Fully wrapped fibre reinforced composite gas cylinders and tubes up to 450 l with load-sharing metal liners, Second edition, 2012-07-13, into § 178.71.
(57) ISO 11119-2:2012/Amd 1:2014 Gas cylinders—Refillable composite gas cylinders and tubes—Design, construction and testing—Part 2: Fully wrapped fibre reinforced composite gas cylinders and tubes up to 450 l with load-sharing metal liners, Second edition, 2014-08-11, into § 178.71.
(58) ISO 11119-3(E), Gas cylinders of composite construction—Specification and test methods—Part 3: Fully wrapped fibre reinforced composite gas cylinders with non-load-sharing metallic or non-metallic liners, First edition, September 2002, into § 178.71.
(59) ISO 11119-3:2013 Gas cylinders—Refillable composite gas cylinders and tubes—Design, construction and testing—Part 3: Fully wrapped fibre reinforced composite gas cylinders and tubes up to 450 l with non-load-sharing metallic or non-metallic liners, Second edition, 2013-04-17, into § 178.71.
(60) ISO 11120(E), Gas cylinders—Refillable seamless steel tubes of water capacity between 150 L and 3000 L—Design, construction and testing, First edition, March 1999, into §§ 178.71; 178.75.
(61) ISO 11513:2011(E), Gas cylinders—Refillable welded steel cylinders containing materials for sub-atmospheric gas packaging (excluding acetylene)—Design, construction, testing, use and periodic inspection, First edition, 2011-09-12, into §§ 173.302c; 178.71; 180.207.
(62) ISO 11515:2013 Gas cylinders—Refillable composite reinforced tubes of water capacity between 450 L and 3000 L—Design, construction and testing, First edition, 2013-07-22, into § 178.71.
(63) ISO 11621(E), Gas cylinders—Procedures for change of gas service, First edition, April 1997, into §§ 173.302, 173.336, 173.337.
(64) ISO 11623(E), Transportable gas cylinders—Periodic inspection and testing of composite gas cylinders, First edition, March 2002, into § 180.207.
(65) ISO 13340:2001(E) Transportable gas cylinders—Cylinder valves for non-refillable cylinders—Specification and prototype testing, First edition, 2004-04-01, into §§ 173.301b; 178.71.
(66) ISO 13736:2008(E), Determination of flash point—Abel closed-cup method, Second Edition, 2008-09-15, into § 173.120.
(67) ISO 16111:2008(E), Transportable gas storage devices—Hydrogen absorbed in reversible metal hydride, First Edition, 2008-11-15, into §§ 173.301b; 173.311; 178.71.
(68) ISO 18172-1:2007(E), Gas cylinders—Refillable welded stainless steel cylinders—Part 1: Test pressure 6 MPa and below, First Edition, 2007-03-01, into § 178.71.
(69) ISO 20703:2006(E), Gas cylinders—Refillable welded aluminum-alloy cylinders—Design, construction and testing, First Edition, 2006-05-01, into § 178.71.
(bb)
(1) Transportation of Dangerous Goods Regulations (Transport Canada TDG Regulations), into §§ 171.12; 171.22; 171.23; 172.401; 172.502; 172.519; 172.602; 173.31; 173.32; 173.33; 180.413.
(xiii) SOR/2014-152 July 2, 2014.
(xiv) SOR/2014-159 July 2, 2014.
(xv) SOR/2014-159 Erratum July 16, 2014.
(xvi) SOR/2014-152 Erratum August 27, 2014.
(xvii) SOR/2014-306 December 31, 2014.
(xviii) SOR/2014-306 Erratum January 28, 2015.
(xix) SOR/2015-100 May 20, 2015.
(dd)
(1) UN Recommendations on the Transport of Dangerous Goods, Model Regulations (UN Recommendations), 19th revised edition, Volumes I and II (2015), into §§ 171.8; 171.12; 172.202; 172.401; 172.407; 172.502; 173.22; 173.24; 173.24b; 173.40; 173.56; 173.192; 173.302b; 173.304b; 178.75; 178.274.
(2) UN Recommendations on the Transport of Dangerous Goods, Manual of Tests and Criteria, (Manual of Tests and Criteria), Sixth revised edition (2015), into §§ 171.24, 172.102; 173.21; 173.56; 173.57; 173.58; 173.60; 173.115; 173.124; 173.125; 173.127; 173.128; 173.137; 173.185; 173.220; 173.221; 173.225, part 173, appendix H; 178.274:
(3) UN Recommendations on the Transport of Dangerous Goods, Globally Harmonized System of Classification and Labelling of Chemicals (GHS), Sixth revised edition (2015), into § 172.401.
The revisions and additions read as follows:
(1) Is designed for mechanical handling; and
(2) Has a net mass greater than 400 kg (882 pounds) or a capacity of greater than 450 L (119 gallons), but has a volume of not more than 3 cubic meters (106 cubic feet).
(a) * * *
(1) A hazardous material transported from Canada to the United States, from the United States to Canada, or transiting the United States to Canada or a foreign destination may be offered for transportation or transported by motor carrier and rail in accordance with the Transport Canada TDG Regulations (IBR, see § 171.7) or an equivalency certificate (permit for equivalent level of safety) issued under the TDG Regulations, as authorized in § 171.22, provided the requirements in §§ 171.22 and 171.23, as applicable, and this section are met. In addition, a cylinder, cargo tank motor vehicle, portable tank or rail tank car authorized by the Transport Canada TDG Regulations may be used for transportation to, from, or within the United States provided the cylinder, cargo tank motor vehicle, portable tank or rail tank car conforms to the applicable requirements of this section. Except as otherwise provided in this subpart and subpart C of this part, the requirements in parts 172, 173, and 178 of this subchapter do not apply for a material transported in accordance with the Transport Canada TDG Regulations.
(4) * * *
(ii) A Canadian Railway Commission (CRC), Board of Transport Commissioners for Canada (BTC), Canadian Transport Commission (CTC) or Transport Canada (TC) specification cylinder manufactured, originally marked, and approved in accordance with the TDG regulations, and in full conformance with the TDG Regulations is authorized for transportation to, from or within the United States provided:
(A) The CRC, BTC, CTC or TC specification cylinder corresponds with a DOT specification cylinder and the markings are the same as those specified in this subchapter, except that the original markings were “CRC”, “BTC”, “CTC”, or “TC”;
(B) The CRC, BTC, CTC or TC cylinder has been requalified under a program authorized by the TDG regulations; and
(C) When the regulations authorize a cylinder for a specific hazardous material with a specification marking prefix of “DOT,” a cylinder marked “CRC”, “BTC”, “CTC”, or “TC” otherwise bearing the same markings required of the specified “DOT” cylinder may be used.
(D) Transport of the cylinder and the material it contains is in all other respects in conformance with the requirements of this subchapter (
(a)
(2) Cylinders (including UN pressure receptacles) transported to, from, or within the United States must conform
(i) The cylinder is manufactured, inspected and tested in accordance with a DOT specification or a UN standard prescribed in part 178 of this subchapter, or a TC, CTC, CRC, or BTC specification set out in the TDG Regulations, except that cylinders not conforming to these requirements must meet the requirements in paragraph (a)(3), (4), or (5) of this section;
(ii) The cylinder is equipped with a pressure relief device in accordance with § 173.301(f) of this subchapter and conforms to the applicable requirements in part 173 of this subchapter for the hazardous material involved;
(iii) The openings on an aluminum cylinder in oxygen service conform to the requirements of this paragraph, except when the cylinder is used for aircraft parts or used aboard an aircraft in accordance with the applicable airworthiness requirements and operating regulations. An aluminum DOT specification cylinder must have an opening configured with straight (parallel) threads. A UN pressure receptacle may have straight (parallel) or tapered threads provided the UN pressure receptacle is marked with the thread type,
(iv) A UN pressure receptacle is marked with “USA” as a country of approval in conformance with §§ 178.69 and 178.70 of this subchapter, or “CAN” for Canada.
(3) Importation of cylinders for discharge within a single port area: A cylinder manufactured to other than a DOT specification or UN standard in accordance with part 178 of this subchapter, or a TC, CTC, BTC, or CRC specification cylinder set out in the TDG Regulations, and certified as being in conformance with the transportation regulations of another country may be authorized, upon written request to and approval by the Associate Administrator, for transportation within a single port area, provided—
(i) The cylinder is transported in a closed freight container;
(ii) The cylinder is certified by the importer to provide a level of safety at least equivalent to that required by the regulations in this subchapter for a comparable DOT, TC, CTC, BTC, or CRC specification or UN cylinder; and
(iii) The cylinder is not refilled for export unless in compliance with paragraph (a)(4) of this section.
(4) Filling of cylinders for export or for use on board a vessel: A cylinder not manufactured, inspected, tested and marked in accordance with part 178 of this subchapter, or a cylinder manufactured to other than a UN standard, DOT specification, exemption or special permit, or other than a TC, CTC, BTC, or CRC specification, may be filled with a gas in the United States and offered for transportation and transported for export or alternatively, for use on board a vessel, if the following conditions are met:
(i) The cylinder has been requalified and marked with the month and year of requalification in accordance with subpart C of part 180 of this subchapter, or has been requalified as authorized by the Associate Administrator;
(ii) In addition to other requirements of this subchapter, the maximum filling density, service pressure, and pressure relief device for each cylinder conform to the requirements of this part for the gas involved; and
(iii) The bill of lading or other shipping paper identifies the cylinder and includes the following certification: “This cylinder has (These cylinders have) been qualified, as required, and filled in accordance with the DOT requirements for export.”
(5) Cylinders not equipped with pressure relief devices: A DOT specification or a UN cylinder manufactured, inspected, tested and marked in accordance with part 178 of this subchapter and otherwise conforms to the requirements of part 173 of this subchapter for the gas involved, except that the cylinder is not equipped with a pressure relief device may be filled with a gas and offered for transportation and transported for export if the following conditions are met:
(i) Each DOT specification cylinder or UN pressure receptacle must be plainly and durably marked “For Export Only”;
(ii) The shipping paper must carry the following certification: “This cylinder has (These cylinders have) been retested and refilled in accordance with the DOT requirements for export.” and
(iii) The emergency response information provided with the shipment and available from the emergency response telephone contact person must indicate that the pressure receptacles are not fitted with pressure relief devices and provide appropriate guidance for exposure to fire.
49 U.S.C. 5101-5128, 44701; 49 CFR 1.81, 1.96 and 1.97.
The additions and revisions read as follows:
(c) * * *
(1) * * *
40 Polyester resin kits consist of two components: A base material (either Class 3 or Division 4.1, Packing Group II or III) and an activator (organic peroxide), each separately packed in an inner packaging. The organic peroxide must be type D, E, or F, not requiring temperature control. The components may be placed in the same outer packaging provided they will not interact dangerously in the event of leakage. The Packing Group assigned will be II or III, according to the classification criteria for either Class 3 or Division 4.1, as appropriate, applied to the base material. Additionally, unless otherwise excepted in this subchapter, polyester resin kits must be packaged in specification combination packagings based on the performance level of the base material contained within the kit.
134 This entry only applies to vehicles powered by wet batteries, sodium batteries, lithium metal batteries or lithium ion batteries and equipment powered by wet batteries or sodium batteries that are transported with these batteries installed.
a. For the purpose of this special provision, vehicles are self-propelled apparatus designed to carry one or more persons or goods. Examples of such vehicles are electrically-powered cars, motorcycles, scooters, three- and four-wheeled vehicles or motorcycles, trucks, locomotives, bicycles (pedal cycles with an electric motor) and other vehicles of this type (
b. Examples of equipment are lawnmowers, cleaning machines or model boats and model aircraft. Equipment powered by lithium metal batteries or lithium ion batteries must be consigned under the entries “Lithium metal batteries contained in equipment” or “Lithium metal batteries packed with equipment” or “Lithium ion batteries contained in equipment” or “Lithium ion batteries packed with equipment” as appropriate.
c. Self-propelled vehicles or equipment that also contain an internal combustion engine must be consigned under the entries “Engine, internal combustion, flammable gas powered” or “Engine, internal combustion, flammable liquid powered” or “Vehicle, flammable gas powered” or “Vehicle, flammable liquid powered,” as appropriate. These entries include hybrid electric vehicles powered by both an internal combustion engine and batteries. Additionally, self-propelled vehicles or equipment that contain a fuel cell engine must be consigned under the entries “Engine, fuel cell, flammable gas powered” or “Engine, fuel cell, flammable liquid powered” or “Vehicle, fuel cell, flammable gas powered” or “Vehicle, fuel cell, flammable liquid powered,” as appropriate. These entries include hybrid electric vehicles powered by a fuel cell engine, an internal combustion engine, and batteries.
135 Internal combustion engines installed in a vehicle must be consigned under the entries “Vehicle, flammable gas powered” or “Vehicle, flammable liquid powered,” as appropriate. If a vehicle is powered by a flammable liquid and a flammable gas internal combustion engine, it must be consigned under the entry “Vehicle, flammable gas powered.” These entries include hybrid electric vehicles powered by both an internal combustion engine and wet, sodium or lithium batteries installed. If a fuel cell engine is installed in a vehicle, the vehicle must be consigned using the entries “Vehicle, fuel cell, flammable gas powered” or “Vehicle, fuel cell, flammable liquid powered,” as appropriate. These entries include hybrid electric vehicles powered by a fuel cell, an internal combustion engine, and wet, sodium or lithium batteries installed. For the purpose of this special provision, vehicles are self-propelled apparatus designed to carry one or more persons or goods. Examples of such vehicles are cars, motorcycles, trucks, locomotives, scooters, three- and four-wheeled vehicles or motorcycles, lawn tractors, self-propelled farming and construction equipment, boats and aircraft.
157 When transported as a limited quantity or a consumer commodity, the maximum net capacity specified in § 173.151(b)(1)(i) of this subchapter for inner packagings may be increased to 5 kg (11 pounds).
181 When a package contains a combination of lithium batteries contained in equipment and lithium batteries packed with equipment, the following requirements apply:
a. The shipper must ensure that all applicable requirements of § 173.185 are met. The total mass of lithium batteries contained in any package must not exceed the quantity limits in columns 9A and 9B for passenger aircraft or cargo aircraft, as applicable;
b. except as provided in § 173.185(c)(3), the package must be marked “UN 3091 Lithium metal
c. the shipping paper must indicate “UN 3091 Lithium metal batteries packed with equipment” or “UN 3481 Lithium ion batteries packed with equipment,” as appropriate. If a package contains both lithium metal batteries and lithium ion batteries packed with and contained in equipment, then the shipping paper must indicate both “UN 3091 Lithium metal batteries packed with equipment” and “UN 3481 Lithium ion batteries packed with equipment.”
182 Equipment containing only lithium batteries must be classified as either UN 3091 or UN 3481.
238 Neutron radiation detectors: a. Neutron radiation detectors containing non-pressurized boron trifluoride gas in excess of 1 gram (0.035 ounces) and radiation detection systems containing such neutron radiation detectors as components may be transported by highway, rail, vessel, or cargo aircraft in accordance with the following:
a. Each radiation detector must meet the following conditions:
(1) The pressure in each neutron radiation detector must not exceed 105 kPa absolute at 20 °C (68 °F);
(2) The amount of gas must not exceed 13 grams (0.45 ounces) per detector; and
(3) Each neutron radiation detector must be of welded metal construction with brazed metal to ceramic feed through assemblies. These detectors must have a minimum burst pressure of 1800 kPa as demonstrated by design type qualification testing; and
(4) Each detector must be tested to a 1 × 10
b. Radiation detectors transported as individual components must be transported as follows:
(1) They must be packed in a sealed intermediate plastic liner with sufficient absorbent or adsorbent material to absorb or adsorb the entire gas contents.
(2) They must be packed in strong outer packagings and the completed package must be capable of withstanding a 1.8 meter (5.9 feet) drop without leakage of gas contents from detectors.
(3) The total amount of gas from all detectors per outer packaging must not exceed 52 grams (1.83 ounces).
c. Completed neutron radiation detection systems containing detectors meeting the conditions of paragraph a(1) of this special provision must be transported as follows:
(1) The detectors must be contained in a strong sealed outer casing;
(2) The casing must contain include sufficient absorbent or adsorbent material to absorb or adsorb the entire gas contents;
(3) The completed system must be packed in strong outer packagings capable of withstanding a 1.8 meter (5.9 feet) drop test without leakage unless a system's outer casing affords equivalent protection.
d. Except for transportation by aircraft, neutron radiation detectors and radiation detection systems containing such detectors transported in accordance with paragraph a. of this special provision are not subject to the labeling and placarding requirements of part 172 of this subchapter.
e. When transported by highway, rail, vessel, or as cargo on an aircraft, neutron radiation detectors containing not more than 1 gram of boron trifluoride, including those with solder glass joints are not subject to any other requirements of this subchapter provided they meet the requirements in paragraph a(1) of this special provision and are packed in accordance with paragraph a(2) of this special provision. Radiation detection systems containing such detectors are not subject to any other requirements of this subchapter provided they are packed in accordance with paragraph a(3) of this special provision.
369 In accordance with § 173.2a, this radioactive material in an excepted package possessing corrosive properties is classified in Division 6.1 with a radioactive material and corrosive subsidiary risk. Uranium hexafluoride may be classified under this entry only if the conditions of §§ 173.420(a)(4) and (6), 173.420(d), 173.421(b) and (d), and, for fissile-excepted material, the conditions of 173.453 of this subchapter are met. In addition to the provisions applicable to the transport of Division 6.1 substances, the provisions of §§ 173.421(c), and 173.443(a) of this subchapter apply. In addition, packages shall be legibly and durably marked with an identification of the consignor, the consignee, or both. No Class 7 label is required to be displayed. The consignor shall be in possession of a copy of each applicable certificate when packages include fissile material excepted by competent authority approval. When a consignment is undeliverable, the consignment shall be placed in a safe location and the appropriate competent authority shall be informed as soon as possible and a request made for instructions on further action. If it is evident that a package of radioactive material, or conveyance carrying unpackaged radioactive material, is leaking, or if it is suspected that the package, or conveyance carrying unpackaged material, may have leaked, the requirements of § 173.443(e) of this subchapter apply.
379 When offered for transport by highway, rail, or cargo vessel, anhydrous ammonia adsorbed or absorbed on a solid contained in ammonia dispensing systems or receptacles intended to form part of such systems is not subject to the requirements of this subchapter if the following conditions in this provision are met. In addition to meeting the conditions in this provision, transport on cargo aircraft only may be authorized with prior approval of the Associate Administrator.
a. The adsorption or absorption presents the following properties:
(1) The pressure at a temperature of 20 °C (68 °F) in the receptacle is less than 0.6 bar (60 kPa);
(2) The pressure at a temperature of 35 °C (95 °F) in the receptacle is less than 1 bar (100 kPa);
(3) The pressure at a temperature of 85 °C (185 °F) in the receptacle is less than 12 bar (1200 kPa).
b. The adsorbent or absorbent material shall not meet the definition or criteria for inclusion in Classes 1 to 8;
c. The maximum contents of a receptacle shall be 10 kg of ammonia; and
d. Receptacles containing adsorbed or absorbed ammonia shall meet the following conditions:
(1) Receptacles shall be made of a material compatible with ammonia as specified in ISO 11114-1:2012 (IBR, see § 171.7 of this subchapter);
(2) Receptacles and their means of closure shall be hermetically sealed and able to contain the generated ammonia;
(3) Each receptacle shall be able to withstand the pressure generated at 85 °C (185 °F) with a volumetric expansion no greater than 0.1%;
(4) Each receptacle shall be fitted with a device that allows for gas evacuation once pressure exceeds 15 bar (1500 kPa) without violent rupture, explosion or projection; and
(5) Each receptacle shall be able to withstand a pressure of 20 bar (2000
e. When offered for transport in an ammonia dispenser, the receptacles shall be connected to the dispenser in such a way that the assembly is guaranteed to have the same strength as a single receptacle.
f. The properties of mechanical strength mentioned in this special provision shall be tested using a prototype of a receptacle and/or dispenser filled to nominal capacity, by increasing the temperature until the specified pressures are reached.
g. The test results shall be documented, shall be traceable, and shall be made available to a representative of the Department upon request.
387 When materials are stabilized by temperature control, the provisions of § 173.21(f) apply. When chemical stabilization is employed, the person offering the material for transport shall ensure that the level of stabilization is sufficient to prevent the material as packaged from dangerous polymerization at 50 °C (122 °F). If chemical stabilization becomes ineffective at lower temperatures within the anticipated duration of transport, temperature control is required and is forbidden by aircraft. In making this determination factors to be taken into consideration include, but are not limited to, the capacity and geometry of the packaging and the effect of any insulation present, the temperature of the material when offered for transport, the duration of the journey, and the ambient temperature conditions typically encountered in the journey (considering also the season of year), the effectiveness and other properties of the stabilizer employed, applicable operational controls imposed by regulation (
422 When labelling is required, the label to be used must be the label shown in § 172.447. Labels conforming to requirements in place on December 31, 2016 may continue to be used until December 31, 2018. When a placard is displayed, the placard must be the placard shown in § 172.560.
(2) * * *
A210 This substance is forbidden for transport by air. It may be transported on cargo aircraft only with the prior approval of the Associate Administrator.
A212 “UN 2031, Nitric acid,
a. Each inner packaging contains not more than 30 mL;
b. Each inner packaging is contained in a sealed leak-proof intermediate packaging with sufficient absorbent material capable of containing the contents of the inner packaging;
c. Intermediate packagings are securely packed in an outer packaging of a type permitted by § 173.158(g) which meet the requirements of part 178 of the HMR at the Packing Group I performance level;
d. The maximum quantity of nitric acid in the package does not exceed 300 mL; and
e. Transport in accordance with this special provision must be noted on the shipping paper.
(3) * * *
B134 For Large Packagings offered for transport by vessel, flexible or fibre inner packagings shall be sift-proof and water-resistant or shall be fitted with a sift-proof and water-resistant liner.
B135 For Large Packagings offered for transport by vessel, flexible or fibre inner packagings shall be hermetically sealed.
(4) * * *
(5) * * *
N90 Metal packagings are not authorized. Packagings of other material with a small amount of metal, for example metal closures or other metal fittings such as those mentioned in part 178 of this subchapter, are not considered metal packagings. Packagings of other material constructed with a small amount of metal must be designed such that the hazardous material does not contact the metal.
N92 Notwithstanding the provisions of § 173.24(g), packagings shall be designed and constructed to permit the release of gas or vapor to prevent a build-up of pressure that could rupture the packagings in the event of loss of stabilization.
(9) * * *
W31 Packagings must be hermetically sealed.
W32 Packagings shall be hermetically sealed, except for solid fused material.
W40 Bags are not allowed.
W100 Flexible, fibreboard or wooden packagings must be sift-proof and water-resistant or must be fitted with a sift-proof and water-resistant liner.
(c) * * *
(1) * * *
(i) If the size of the package so requires, the dimensions of the label and its features may be reduced proportionally provided the symbol and other elements of the label remain clearly visible.
(iii)
(a) Except for size and color, the LITHIUM BATTERY label must be as follows:
(b) In addition to complying with § 172.407, the background on the LITHIUM BATTERY label must be white with seven black vertical stripes on the top half. The black vertical stripes must be spaced, so that, visually, they appear equal in width to the six white spaces between them. The lower half of the label must be white with the symbol (battery group, one broken and emitting flame) and class number “9” underlined and centered at the bottom in black.
(c) Labels conforming to requirements in place on December 31, 2016 may continue to be used until December 31, 2018.
(b) In addition to the RADIOACTIVE placard which may be required by § 172.504(e), each transport vehicle, portable tank or freight container that contains 454 kg (1,001 pounds) or more gross weight of non-fissile, fissile-excepted, or fissile uranium hexafluoride must be placarded with a CORROSIVE placard and a POISON placard on each side and each end.
49 U.S.C. 5101-5128, 44701; 49 CFR 1.81, 1.96 and 1.97.
(e) * * *
(3) Each inner packaging must be securely packed in an intermediate packaging with cushioning material in such a way that, under normal conditions of transport, it cannot break, be punctured or leak its contents. The completed package as prepared for transport must completely contain the contents in case of breakage or leakage, regardless of package orientation. For liquid hazardous materials, the intermediate or outer packaging must contain sufficient absorbent material that:
(i) Will absorb the entire contents of the inner packaging.
(ii) Will not react dangerously with the material or reduce the integrity or function of the packaging materials.
(iii) When placed in the intermediate packaging, the absorbent material may be the cushioning material.
(e)
(i) The marking, and all required information, must be capable of withstanding, without deterioration or a substantial reduction in effectiveness, a 30-day exposure to open weather conditions.
(ii) [Reserved]
(2) The “*” shall be replaced with the technical name of the fumigant.
(f) A package containing a material which is likely to decompose with a self-accelerated decomposition temperature (SADT) or a self-accelerated polymerization temperature (SAPT) of 50 °C (122 °F) or less, with an evolution of a dangerous quantity of heat or gas when decomposing or polymerizing, unless the material is stabilized or inhibited in a manner to preclude such evolution. The SADT and SAPT may be determined by any of the test methods described in Part II of the UN Manual of Tests and Criteria (IBR, see § 171.7 of this subchapter).
(1) A package meeting the criteria of paragraph (f) of this section may be required to be shipped under controlled temperature conditions. The control temperature and emergency temperature for a package shall be as specified in the table in this paragraph based upon the SADT or SAPT of the material. The control temperature is the temperature above which a package of the material may not be offered for transportation or transported. The emergency temperature is the temperature at which, due to imminent danger, emergency measures must be initiated.
(a) * * *
(1) A cylinder must conform to a DOT specification or UN standard prescribed in subpart C of part 178 of this subchapter, or a TC, CTC, CRC, or BTC cylinder authorized in § 171.12 of this subchapter, except that acetylene cylinders are not authorized. The use of UN tubes and MEGCs is prohibited for Hazard Zone A materials.
(b) * * *
(6) Division 1.6
(b) * * *
(b) * * *
(c) * * *
(b) * * *
(1) * * *
(iv) The viscosity
(a)
(1) Desensitized explosives that—
(i) When dry are Explosives of Class 1 other than those of compatibility group A, which are wetted with sufficient water, alcohol, or plasticizer to suppress explosive properties; and
(ii) Are specifically authorized by name either in the Hazardous Materials Table in § 172.101 or have been assigned a shipping name and hazard class by the Associate Administrator under the provisions of—
(A) A special permit issued under subchapter A of this chapter; or
(B) An approval issued under § 173.56(i) of this part.
(2)(i) Self-reactive materials that are thermally unstable and can undergo an exothermic decomposition even without participation of oxygen (air). A material is excluded from this definition if any of the following applies:
(A) The material meets the definition of an explosive as prescribed in subpart C of this part, in which case it must be classed as an explosive;
(B) The material is forbidden from being offered for transportation according to § 172.101 of this subchapter or § 173.21;
(C) The material meets the definition of an oxidizer or organic peroxide as prescribed in subpart D of this part, in which case it must be so classed;
(D) The material meets one of the following conditions:
(
(
(
(E) The Associate Administrator has determined that the material does not present a hazard which is associated with a Division 4.1 material.
(ii)
(A)
(B)
(C)
(D)
(
(
(
(E)
(F)
(G)
(iii)
(A) Its physical state (
(B) A determination as to its control temperature and emergency temperature, if any, under the provisions of § 173.21(f);
(C) Performance of the self-reactive material under the test procedures specified in the UN Manual of Tests and Criteria (IBR, see § 171.7 of this subchapter) and the provisions of paragraph (a)(2)(iii) of this section; and
(D) Except for a self-reactive material which is identified by technical name in the Self-Reactive Materials Table in § 173.224(b) or a self-reactive material which may be shipped as a sample under the provisions of § 173.224, the self-reactive material is approved in writing by the Associate Administrator. The person requesting approval shall submit to the Associate Administrator the tentative shipping description and generic type and—
(
(
(iv)
(3) Readily combustible solids are materials that—
(i) Are solids which may cause a fire through friction, such as matches;
(ii) Show a burning rate faster than 2.2 mm (0.087 inches) per second when tested in accordance with the UN Manual of Tests and Criteria (IBR, see § 171.7 of this subchapter); or
(iii) Any metal powders that can be ignited and react over the whole length of a sample in 10 minutes or less, when tested in accordance with the UN Manual of Tests and Criteria.
(4) Polymerizing materials are materials that are liable to undergo an exothermic reaction resulting in the formation of larger molecules or resulting in the formation of polymers under conditions normally encountered in transport. Such materials are considered to be polymerizing substances of Division 4.1 when:
(i) Their self-accelerating polymerization temperature (SAPT) is 75 °C (167 °F) or less under the conditions (with or without chemical stabilization) as offered for transport in the packaging, IBC or portable tank in which the material or mixture is to be transported. An appropriate packaging for a polymerizing material must be determined using the heating under confinement testing protocol from boxes 7, 8, 9, and 13 of Figure 20.1 (a) and (b) (Flow Chart Scheme for Self-Reactive Substances and Organic Peroxides) from the UN Manual of Tests and Criteria (IBR, see § 171.7 of this subchapter) by successfully passing the UN Test Series E at the “None” or “Low” level or by an equivalent test method;
(ii) They exhibit a heat of reaction of more than 300 J/g; and
(iii) Do not meet the definition of any other hazard class.
(b)
(1)
(2)
(c)
(a) Polyester resin kits consisting of a base material component (Class 3, Packing Group II or III) or (Division 4.1, Packing Group II or III) and an activator
(1) The organic peroxide component must be packed in inner packagings not over 125 mL (4.22 fluid ounces) net capacity each for liquids or 500 g (17.64 ounces) net capacity each for solids.
(2) Except for transportation by aircraft, the flammable liquid component must be packaged in suitable inner packagings.
(i) For transportation by aircraft, a Class 3 Packing Group II base material is limited to a quantity of 5 L (1.3 gallons) in metal or plastic inner packagings and 1 L (0.3 gallons) in glass inner packagings. A Class 3 Packing Group III base material is limited to a quantity of 10 L (2.6 gallons) in metal or plastic inner packagings and 2.5 L (0.66 gallons) in glass inner packagings.
(ii) For transportation by aircraft, a Division 4.1 Packing Group II base material is limited to a quantity of 5 kg (11 pounds) in metal or plastic inner packagings and 1 kg (2.2 pounds) in glass inner packagings. A Division 4.1 Packing Group III base material is limited to a quantity of 10 kg (22 lbs) in metal or plastic inner packagings and 2.5 kg (5.5 pounds) in glass inner packagings.
(3) If the flammable liquid or solid component and the organic peroxide component will not interact dangerously in the event of leakage, they may be packed in the same outer packaging.
(4) The Packing Group assigned will be II or III, according to the criteria for Class 3, or Division 4.1, as appropriate, applied to the base material. Additionally, polyester resin kits must be packaged in specification combination packagings, based on the performance level required of the base material (II or III) contained within the kit, as prescribed in § 173.202, 173.203, 173.212, or 173.213 of this subchapter, as appropriate.
(5) For transportation by aircraft, the following additional requirements apply:
(i) Closures on inner packagings containing liquids must be secured by secondary means;
(ii) Inner packagings containing liquids must be capable of meeting the pressure differential requirements prescribed in § 173.27(c); and
(iii) The total quantity of activator and base material may not exceed 5 kg (11 lbs) per package for a Packing Group II base material. The total quantity of activator and base material may not exceed 10 kg (22 lbs) per package for a Packing Group III base material. The total quantity of polyester resin kits per package is calculated on a one-to-one basis (
(b) Polyester resin kits are eligible for the Small Quantity exceptions in § 173.4 and the Excepted Quantity exceptions in § 173.4a, as applicable.
(c)
(1) Except for transportation by aircraft, the organic peroxide component must be packed in inner packagings not over 125 mL (4.22 fluid ounces) net capacity each for liquids or 500 g (17.64 ounces) net capacity each for solids. For transportation by aircraft, the organic peroxide component must be packed in inner packagings not over 30 mL (1 fluid ounce) net capacity each for liquids or 100 g (3.5 ounces) net capacity each for solids.
(2) Except for transportation by aircraft, the flammable liquid component must be packed in inner packagings not over 5 L (1.3 gallons) net capacity each for a Packing Group II and Packing Group III liquid. For transportation by aircraft, the flammable liquid component must be packed in inner packagings not over 1 L (0.3 gallons) net capacity each for a Packing Group II material. For transportation by aircraft, the flammable liquid component must be packed in metal or plastic inner packagings not over 5.0 L (1.3 gallons) net capacity each or glass inner packagings not over 2.5 L (0.66 gallons) net capacity each for a Packing Group III material.
(3) Except for transportation by aircraft, the flammable solid component must be packed in inner packagings not over 5 kg (11 pounds) net capacity each for a Packing Group II and Packing Group III solid. For transportation by aircraft, the flammable solid component must be packed in inner packagings not over 1 kg (2.2 pounds) net capacity each for a Packing Group II material. For transportation by aircraft, the flammable solid component must be packed in metal or plastic inner packagings not over 5.0 kg (11 pounds) net capacity each or glass inner packagings not over 2.5 kg (5.5 pounds) net capacity each for a Packing Group III material.
(4) If the flammable liquid or solid component and the organic peroxide component will not interact dangerously in the event of leakage, they may be packed in the same outer packaging.
(5) For transportation by aircraft, the following additional requirements apply:
(i) Closures on inner packagings containing liquids must be secured by secondary means as prescribed in § 173.27(d);
(ii) Inner packagings containing liquids must be capable of meeting the pressure differential requirements prescribed in § 173.27(c); and
(iii) The total quantity of activator and base material may not exceed 1 kg (2.2 pounds) per package for a Packing Group II base material. The total quantity of activator and base material may not exceed 5 kg (11 pounds) per package for a Packing Group III base material. The total quantity of polyester resin kits per package is calculated on a one-to-one basis (
(iv)
(v)
(d)
As used in this section,
(c) * * *
(2)
(3)
(i) The mark must indicate the UN number, `UN3090' for lithium metal cells or batteries or `UN 3480' for lithium ion cells or batteries. Where the lithium cells or batteries are contained in, or packed with, equipment, the UN number `UN3091' or `UN 3481' as appropriate must be indicated. Where a package contains lithium cells or batteries assigned to different UN numbers, all applicable UN numbers must be indicated on one or more marks. The package must be of such size that there is adequate space to affix the mark on one side without the mark being folded. [PHOTO]
(A) The mark must be in the form of a rectangle with hatched edging. The mark must be not less than 120 mm (4.7 inches) wide by 110 mm (4.3 inches) high and the minimum width of the hatching must be 5 mm (0.2 inches) except markings of 105 mm (4.1 inches) wide by 74 mm (2.9 inches) high may be used on a package containing lithium batteries when the package is too small for the larger mark;
(B) The symbols and letters must be black on white or suitable contrasting background and the hatching must be red;
(C) The “*” must be replaced by the appropriate UN number(s) and the “**” must be replaced by a telephone number for additional information; and
(D) Where dimensions are not specified, all features shall be in approximate proportion to those shown.
(ii) The provisions for marking packages in effect on December 31, 2016 may continue to be used until December 31, 2018.
(4) * * *
(ii) When packages required to bear the lithium battery mark in paragraph (c)(3)(i) are placed in an overpack, the lithium battery mark must either be clearly visible through the overpack, or the handling marking must also be affixed on the outside of the overpack, and the overpack must be marked with the word “OVERPACK”.
(e)
(1) Except as provided in paragraph (e)(3) of this section, each cell or battery is individually packed in a non-metallic inner packaging, inside an outer packaging, and is surrounded by cushioning material that is non-combustible and non-conductive or contained in equipment. Equipment must be constructed or packaged in a manner as to prevent accidental operation during transport;
(2) Appropriate measures shall be taken to minimize the effects of vibration and shocks and prevent movement of the cells or batteries within the package that may lead to damage and a dangerous condition during transport. Cushioning material that is non-combustible and non-conductive may be used to meet this requirement
(3) The lithium cells or batteries are packed in inner packagings or contained in equipment. The inner packaging or equipment is placed in one of the following outer packagings that meet the requirements of part 178, subparts L and M at the Packing Group I level. Cells and batteries, including equipment of different sizes, shapes or masses must be placed into an outer packaging of a tested design type listed in this section provided the total gross mass of the package does not exceed the gross mass for which the design type has been tested. A cell or battery with a net mass of more than 30 kg is limited to one cell or battery per outer packaging;
(i) Metal (4A, 4B, 4N), wooden (4C1, 4C2, 4D, 4F), or solid plastic (4H2) box;
(ii) Metal (1A2, 1B2, 1N2), plywood (1D), or plastic (1H2) drum.
(4) Lithium batteries that weigh 12 kg (26.5 pounds) or more and have a strong, impact-resistant outer casing or assemblies of such batteries, may be packed in strong outer packagings, in protective enclosures (for example, in fully enclosed or wooden slatted crates), or on pallets or other handling devices, instead of packages meeting the UN performance packaging requirements in paragraphs (b)(3)(ii) and (iii) of this section. The battery or battery assembly must be secured to prevent inadvertent movement, and the terminals may not support the weight of other superimposed elements;
(5) Irrespective of the limit specified in column (9B) of the § 172.101 Hazardous Materials Table, the battery or battery assembly prepared for transport in accordance with this paragraph may have a mass exceeding 35 kg gross weight when transported by cargo aircraft;
(6) Batteries or battery assemblies packaged in accordance with this paragraph are not permitted for transportation by passenger-carrying aircraft, and may be transported by cargo aircraft only if approved by the Associate Administrator prior to transportation; and
(7) Shipping papers must include the following notation “Transport in accordance with § 173.185(e).”
(f) * * *
(4) The outer package must be marked with an indication that the package contains a “Damaged/defective lithium ion battery” and/or “Damaged/defective lithium metal battery” as appropriate. The marking required by this paragraph must be in characters at least 12 mm (0.47 inches) high.
(c) * * *
(3) The quantity limits per package shown in Columns (9A) and (9B) of the Hazardous Materials Table in § 172.101 are not applicable to dry ice being used as a refrigerant for other than hazardous materials loaded in a unit load device. In such a case, the unit load device must be identified to the operator and allow the venting of the carbon dioxide gas to prevent a dangerous build-up of pressure.
(a)
(1) The vehicle, engine, or machinery contains a liquid or gaseous fuel. Vehicles, engines, or machinery may be considered as not containing fuel when the engine components and any fuel lines have been completely drained, sufficiently cleaned of residue, and purged of vapors to remove any potential hazard and the engine when held in any orientation will not release any liquid fuel;
(2) The fuel tank contains a liquid or gaseous fuel. A fuel tank may be considered as not containing fuel when the fuel tank and the fuel lines have been completely drained, sufficiently cleaned of residue, and purged of vapors to remove any potential hazard;
(3) It is equipped with a wet battery (including a non-spillable battery), a sodium battery or a lithium battery; or
(4) Except as provided in paragraph (f)(1) of this section, it contains other hazardous materials subject to the requirements of this subchapter.
(b)
(1)
(ii) Engines and machinery containing liquid fuels meeting the definition of a marine pollutant (see § 171.8 of this subchapter) and not meeting the classification criteria of any other Class or Division transported by vessel are subject to the requirements of § 176.906 of this subchapter.
(2)
(ii) For transportation by aircraft:
(A) Flammable gas-powered vehicles, machines, equipment or cylinders containing the flammable gas must be completely emptied of flammable gas. Lines from vessels to gas regulators, and gas regulators themselves, must also be drained of all traces of flammable gas. To ensure that these conditions are met, gas shut-off valves must be left open and connections of lines to gas regulators must be left disconnected upon delivery of the vehicle to the operator. Shut-off valves must be closed and lines
(B) Flammable gas powered vehicles, machines or equipment, which have cylinders (fuel tanks) that are equipped with electrically operated valves, may be transported under the following conditions:
(
(
(
(
(3)
(4)
(i) For transportation by motor vehicle or rail car, the fuel tanks must be securely closed.
(ii) For transportation by vessel, the shipment must conform to § 176.905 of this subchapter for self-propelled vehicles and § 176.906 of this subchapter for engines and machinery.
(iii) For transportation by aircraft, when carried in aircraft designed or modified for vehicle ferry operations when all the following conditions must be met:
(A) Authorization for this type operation has been given by the appropriate authority in the government of the country in which the aircraft is registered;
(B) Each vehicle is secured in an upright position;
(C) Each fuel tank is filled in a manner and only to a degree that will preclude spillage of fuel during loading, unloading, and transportation; and
(D) Each area or compartment in which a self-propelled vehicle is being transported is suitably ventilated to prevent the accumulation of fuel vapors.
(c)
(d)
(e)
(f)
(2) Other hazardous materials must be packaged and transported in accordance with the requirements of this subchapter.
(g)
(h)
(1) Are not subject to any other requirements of this subchapter for transportation by motor vehicle or rail car;
(2) Are not subject to the requirements of subparts D, E, and F (marking, labeling and placarding, respectively) of part 172 of this subchapter or § 172.604 of this subchapter (emergency response telephone number) for transportation by aircraft. For transportation by aircraft, the provisions of § 173.159(b)(2) of this subchapter as applicable, the provisions of § 173.230(f), as applicable, other applicable requirements of this subchapter, including shipping papers, emergency response information, notification of pilot-in-command, general packaging requirements, and the requirements specified in § 173.27 must be met; and
(3) For exceptions for transportation by vessel; see § 176.905 of this subchapter for vehicles, and § 176.906 of this subchapter for engines and machinery.
(d) Exceptions. When it can be demonstrated that no flammable vapor, resulting in a flammable atmosphere, is evolved according to test U1 (Test method for substances liable to evolve flammable vapors) of Part III, sub-section 38.4.4 of the UN Manual of Tests and Criteria (IBR, see § 171.7 of this subchapter), polymeric beads, expandable need not be classed as Class 9 (UN2211). This test should only be performed when de-classification of a substance is considered.
The revisions are to read as follows:
(c) * * *
(8) * * *
(e) * * *
(a) * * *
(2) The gases or gas mixtures must be compatible with the UN pressure receptacle and valve materials as prescribed for metallic materials in ISO 11114-1:2012 (IBR, see § 171.7 of this subchapter) and for non-metallic materials in ISO 11114-2:2013 Gas cylinders—Compatibility of cylinder and valve materials with gas contents—Part 2: Non-metallic materials (IBR, see § 171.7 of this subchapter).
(c) * * *
(1) When the use of a valve is prescribed, the valve must conform to the requirements in ISO 10297:2006 (IBR, see § 171.7 of this subchapter). Until December 31, 2020, the manufacture of a valve conforming to the requirements in ISO 10297:2006 (IBR, see § 171.7 of this subchapter) is authorized. Until December 31, 2008, the manufacture of a valve conforming to the requirements in ISO 10297:1999 (IBR, see § 171.7 of this subchapter) is authorized.
(g)
(f) * * *
(1) UN cylinders and bundles of cylinders are authorized for the transport of acetylene gas as specified in this section.
(i) Each UN acetylene cylinder must conform to ISO 3807:2013:Gas cylinders—Acetylene cylinders—Basic requirements and type testing (IBR, see § 171.7 of this subchapter), have a homogeneous monolithic porous mass filler and be charged with acetone or a suitable solvent as specified in the standard. UN acetylene cylinders must have a minimum test pressure of 52 bar and may be filled up to the pressure limits specified in ISO 3807-2013. The use of UN tubes and MEGCs is not authorized.
(ii) Until December 31, 2020, cylinders conforming to the requirements in ISO 3807-2: Cylinders for acetylene—Basic requirements—Part 2: Cylinders with fusible plugs. (IBR, see § 171.7 of this subchapter), having a homogeneous monolithic porous mass filler and charged with acetone or a suitable solvent as specified in the standard are authorized. UN acetylene cylinders must have a minimum test pressure of 52 bar and may be filled up to the pressure limits specified in ISO 3807-2.
(b) * * *
(5) For liquefied gases charged with compressed gases, both components—the liquid phase and the compressed gas—have to be taken into consideration in the calculation of the internal pressure in the pressure receptacle. The maximum mass of contents per liter of water capacity shall not exceed 95 percent of the density of the liquid phase at 50 °C (122 °F); in addition, the liquid phase shall not completely fill the pressure receptacle at any temperature up to 60 °C (140 °F). When filled, the internal pressure at 65 °C (149 °F) shall not exceed the test pressure of the pressure receptacles. The vapor pressures and volumetric expansions of all substances in the pressure receptacles shall be considered. The maximum filling limits may be determined using the procedure in (3)(e) of P200 of the UN Recommendations.
Radiation detectors, radiation sensors, electron tube devices, or ionization chambers, herein referred to as “radiation detectors,” that contain only Division 2.2 gases in non-refillable cylinders, are excepted from the specification packaging in this subchapter and, except when transported by air, from labeling and placarding requirements of this subchapter when designed, packaged, and transported as follows:
(a) Radiation detectors must be single-trip, hermetically sealed, welded metal inside containers that will not fragment upon impact.
(b) Radiation detectors must not have a design pressure exceeding 5.00 MPa (725 psig) and a capacity exceeding 405 fluid ounces (731 cubic inches). They must be designed and fabricated with a burst pressure of not less than three times the design pressure if the radiation detector is equipped with a pressure relief device, and not less than four times the design pressure if the detector is not equipped with a pressure relief device.
(c) Radiation detectors must be shipped in a strong outer packaging capable of withstanding a drop test of at least 1.2 meters (4 feet) without breakage of the radiation detector or rupture of the outer packaging. If the radiation detector is shipped as part of other equipment, the equipment must be packaged in strong outer packaging or the equipment itself must provide an equivalent level of protection.
(d) Emergency response information accompanying each shipment and available from each emergency response telephone number for radiation detectors must identify those receptacles that are not fitted with a pressure relief device and provide appropriate guidance for exposure to fire.
(e) Transport in accordance with this section must be noted on the shipping paper.
(f) Radiation detectors, including detectors in radiation detection systems, are not subject to any other requirements of this subchapter if the detectors meet the requirements in paragraphs (a) through (d) of this section and the capacity of detector receptacles does not exceed 50 ml (1.69 fluid ounces).
(a)
49 U.S.C. 5101-5128, 44701; 49 CFR 1.81 and 1.97.
(a) * * *
(7) A small medical or clinical mercury thermometer for personal use, when carried in a protective case in checked baggage.
(a) Each person who engages in for hire air transportation of passengers must effectively inform passengers about hazardous materials that passengers are forbidden to transport on aircraft and must accomplish this through the development, implementation, and maintenance of a passenger notification system.
(b)
(1) A passenger is presented with information required under paragraph (a) of this section at the point of ticket purchase or, if this is not practical, in another way prior to boarding pass issuance;
(2) A passenger is presented with information required under paragraph (a) of this section at the point of boarding pass issuance (
(3) A passenger, where the ticket purchase and/or boarding pass issuance can be completed by a passenger without the involvement of another person, acknowledges that they have been presented with the information required under paragraph (a) of this section; and
(4) A passenger is presented with information required under paragraph (a) of this section at each of the places at an airport where tickets are issued, boarding passes are issued, passenger baggage is dropped off, aircraft boarding areas are maintained, and at any other location where boarding passes are issued and/or checked baggage is accepted. This information must include visual examples of forbidden hazardous materials.
(c)
(a) * * *
(3) The net quantity or gross weight, as applicable, for each package except those containing Class 7 (radioactive) materials. For a shipment consisting of multiple packages containing hazardous materials bearing the same proper shipping name and identification number, only the total quantity and an indication of the quantity of the largest and smallest package at each loading location need to be provided. For consumer commodities, the information provided may be either the gross mass of each package or the average gross mass of the packages as shown on the shipping paper;
Carbon dioxide, solid (dry ice) when shipped by itself or when used as a refrigerant for other commodities, may be carried only if the operator has made suitable arrangements based on the aircraft type, the aircraft ventilation rates, the method of packing and stowing, whether animals will be carried on the same flight and other factors. The operator must ensure that the ground staff is informed that the dry ice is being loaded or is on board the aircraft. For arrangements between the shipper and operator, see § 173.217 of this subchapter. Where dry ice is contained in a unit load device (ULD) prepared by a single shipper in accordance with § 173.217 of this subchapter and the operator after the acceptance adds additional dry ice, the operator must ensure that the information provided to the pilot-in-command and the marking on the ULD when used as a packaging reflects that revised quantity of dry ice.
49 U.S.C. 5101-5128; 49 CFR 1.81 and 1.97.
(a) * * *
(4) * * *
(ii) Between hazardous materials of different classes which comprise a group of substances that do not react dangerously with each other. The following materials are grouped by compatibility:
(A) Hydrogen peroxide, aqueous solutions
(B) Dichlorosilane, Silicon tetrachloride, and Trichlorosilane; and
(C) Organometallic substance, solid, pyrophoric, Organometallic substance, liquid, pyrophoric, Organometallic substance, solid, pyrophoric, water-reactive, Organometallic substance, liquid, pyrophoric, water-reactive, Organometallic substance, solid, water-reactive, Organometallic substance, solid, water-reactive, flammable, Organometallic substance, solid, water-reactive, self-heating, Organometallic substance, liquid, water-reactive, Organometallic substance, liquid, water-reactive, flammable, and Organometallic substance, solid, self-heating.
(b) * * *
(a) A vehicle powered by an internal combustion engine, a fuel cell, batteries or a combination thereof is subject to the following requirements when carried as cargo on a vessel:
(1) Before being loaded on a vessel, each vehicle must be inspected for signs of leakage from batteries, engines, fuel cells, compressed gas cylinders or accumulators, or fuel tank(s) when applicable, and any identifiable faults in the electrical system that could result in short circuit or other unintended electrical source of ignition. A vehicle showing any signs of leakage or electrical fault may not be transported.
(2) For flammable liquid powered vehicles, the fuel tank(s) containing the flammable liquid, may not be more than one fourth full and the flammable liquid must not exceed 250 L (66 gal) unless otherwise approved by the Associate Administrator.
(3) For flammable gas powered vehicles, the fuel shut-off valve of the fuel tank(s) must be securely closed.
(4) For vehicles with batteries installed, the batteries shall be protected from damage, short circuit, and accidental activation during transport. Except for vehicles with prototype or low production lithium batteries (see § 173.185(d) of this subchapter) securely installed, each lithium battery must be of a type that has successfully passed each test in the UN Manual of Tests and Criteria (IBR, see § 171.7 of this subchapter), as specified in § 173.185(a) of this subchapter, unless approved by the Associate Administrator. Where a lithium battery installed in a vehicle is damaged or defective, the battery must be removed and transported according to § 173.185(f) of this subchapter, unless otherwise approved by the Associate Administrator.
(5) Whenever possible, each vehicle must be stowed to allow for its inspection during transportation.
(6) Vehicles may be refueled when necessary in the hold of a vessel in accordance with § 176.78.
(b) All equipment used for handling vehicles must be designed so that the fuel tank and the fuel system of the vehicle are protected from stress that might cause rupture or other damage incident to handling.
(c) Two hand-held, portable, dry chemical fire extinguishers of at least 4.5 kg (10 pounds) capacity each must be separately located in an accessible location in each hold or compartment in which any vehicle is stowed.
(d) “NO SMOKING” signs must be conspicuously posted at each access opening to the hold or compartment.
(e) Each portable electrical light, including a flashlight, used in the stowage area must be an approved, explosion-proof type. All electrical connections for any light must be made to outlets outside the space in which any vehicle is stowed.
(f) Each hold or compartment must be ventilated and fitted with an overhead water sprinkler system or fixed fire extinguisher system.
(g) Each hold or compartment must be equipped with a smoke or fire detection system capable of alerting personnel on the bridge.
(h) All electrical equipment in the hold or compartment other than fixed explosion-proof lighting must be disconnected from its power source at a location outside the hold or compartment during the handling and transportation of any vehicle. Where the disconnecting means is a switch or circuit breaker, it must be locked in the open position until all vehicles have been removed.
(i)
(1) The vehicle is stowed in a hold or compartment designated by the administration of the country in which the vessel is registered as specially designed and approved for vehicles and there are no signs of leakage from the battery, engine, fuel cell, compressed gas cylinder or accumulator, or fuel tank, as appropriate. For vehicles with batteries connected and fuel tanks containing gasoline transported by U.S. vessels, see 46 CFR 70.10-1 and 90.10-38;
(i) For vehicles powered solely by lithium batteries and hybrid electric vehicles powered by both an internal combustion engine and lithium metal or ion batteries offered in accordance with this paragraph, the lithium batteries, except for prototype or those produced in low production, must be of a type that has successfully passed each test in the UN Manual of Tests and Criteria (IBR, see § 171.7 of this subchapter), as specified in § 173.185(a) of this subchapter. Where a lithium battery installed in a vehicle is damaged or defective, the battery must be removed.
(ii) [Reserved].
(2) The vehicle is powered by a flammable liquid that has a flashpoint of 38 °C (100 °F) or above, the fuel tank contains 450 L (119 gallons) of fuel or less, there are no leaks in any portion of the fuel system, and installed batteries are protected from short circuit;
(3) The vehicle is powered by a flammable liquid fuel that has a flashpoint less than 38 °C (100 °F), the fuel tank is empty, and installed batteries are protected from short circuit. Vehicles are considered to be empty of flammable liquid fuel when the fuel tank has been drained and the
(4) The vehicle is powered by a flammable gas (liquefied or compressed), the fuel tanks are empty and the positive pressure in the tank does not exceed 2 bar (29 psig), the fuel shut-off or isolation valve is closed and secured, and installed batteries are protected from short circuit;
(5) The vehicle is solely powered by a wet or dry electric storage battery or a sodium battery, and the battery is protected from short circuit; or
(6) The vehicle is powered by a fuel cell engine, the engine is protected from inadvertent operation by closing fuel supply lines or by other means, and the fuel supply reservoir has been drained and sealed.
(j) Except as provided in § 173.220(f) of this subchapter, the provisions of this subchapter do not apply to items of equipment such as fire extinguishers, compressed gas accumulators, airbag inflators and the like which are installed in the vehicle if they are necessary for the operation of the vehicle, or for the safety of its operator or passengers.
(a) Any engine or machinery powered by internal combustion systems, with or without batteries installed, is subject to the following requirements when carried as cargo on a vessel:
(1) Before being loaded on a vessel, each engine or machinery must be inspected for fuel leaks and identifiable faults in the electrical system that could result in short circuit or other unintended electrical source of ignition. Engines or machinery showing any signs of leakage or electrical fault may not be transported.
(2) The fuel tanks of an engine or machinery powered by liquid fuel may not be more than one-fourth full.
(3) Whenever possible, each engine or machinery must be stowed to allow for its inspection during transportation.
(b) All equipment used for handling engines or machinery must be designed so that the fuel tank and the fuel system of the engines or machinery are protected from stress that might cause rupture or other damage incident to handling.
(c) Two hand-held, portable, dry chemical fire extinguishers of at least 4.5 kg (10 pounds) capacity each must be separately located in an accessible location in each hold or compartment in which engine or machinery is stowed.
(d) “NO SMOKING” signs must be conspicuously posted at each access opening to the hold or compartment.
(e) Each portable electrical light, including a flashlight, used in the stowage area must be an approved, explosion-proof type. All electrical connections for any light must be made to outlets outside the space in which any engine or machinery is stowed.
(f) Each hold or compartment must be ventilated and fitted with an overhead water sprinkler system or fixed fire extinguisher system.
(g) Each hold or compartment must be equipped with a smoke or fire detection system capable of alerting personnel on the bridge.
(h) All electrical equipment in the hold or compartment other than fixed explosion-proof lighting must be disconnected from its power source at a location outside the hold or compartment during the handling and transportation of any engine or machinery. Where the disconnecting means is a switch or circuit breaker, it must be locked in the open position until all engines or machinery has been removed.
(i)
(i) For liquid fuels, the liquid fuel tank has been drained and the mechanical equipment cannot be operated due to a lack of fuel. Engine and machinery components such as fuel lines, fuel filters and injectors do not need to be cleaned, drained or purged to be considered empty of liquid fuels. In addition, the liquid fuel tank does not need to be cleaned or purged;
(ii) For gaseous fuels, the gaseous fuel tanks are empty of liquid (for liquefied gases), the positive pressure in the tanks does not exceed 2 bar (29 psig) and the fuel shut-off or isolation valve is closed and secured; or
(iii) The engine or machinery is powered by a fuel cell engine and the engine is protected from inadvertent operation by closing fuel supply lines or by other means, and the fuel supply reservoir has been drained and sealed.
(2) An engine or machinery is not subject to the requirements of this subchapter except for § 173.185 of this subchapter and the vessel stowage provisions of column 10 of table § 172.101 of this subchapter, if the following are met:
(i) Any valves or openings (
(ii) The engines or machinery must be oriented to prevent inadvertent leakage of dangerous goods and secured by means capable of restraining the engines or machinery to prevent any movement during transport which would change the orientation or cause them to be damaged;
(iii) For UN 3528 and UN 3530:
(A) Where the engine or machinery contains more than 60 L (16 Gal) of liquid fuel and has a capacity of not more than 450 L (119 Gal), it shall be labelled in accordance with subpart E of part 172 of this subchapter;
(B) Where the engine or machinery contains more than 60 L of liquid fuel and has a capacity of more than 450 L (119 Gal) but not more than 3,000 L (793 Gal), it shall be labeled on two opposing sides in accordance with § 172.406(e) of this subchapter;
(C) Where the engine or machinery contains more than 60 L (16 Gal) of liquid fuel and has a capacity of more than 3,000 L (793 Gal), it shall be placarded on two opposing sides in accordance with subpart F of part 172 of this subchapter; and
(D) For UN 3530 the marking requirements of § 172.322 of this subchapter also apply.
(iv) For UN 3529:
(A) Where the fuel tank of the engine or mechanical equipment has a water capacity of not more than 450 L (119 Gal), the labeling requirements of subpart E of part 172 of this subchapter shall apply;
(B) Where the fuel tank of the mechanical equipment has a water capacity of more than 450 L (119 Gal) but not more than 1,000 L (264 Gal), it shall be labeled on two opposing sides in accordance with § 172.406(e) of this subchapter;
(C) Where the fuel tank of the mechanical equipment has a water capacity of more than 1,000 L (264 Gal), it shall be placarded on two opposing sides in accordance with subpart F of this subchapter.
(v) Except for engines or machinery offered in accordance with paragraph (i)(1) of this section, a shipping paper prepared in accordance with part 172 of this subchapter is required and shall contain the following additional statement “Transport in accordance with § 176.906.” For transportation in accordance with the IMDG Code (IBR, see § 171.7 of this subchapter) the following alternative statement is
(j) Except as provided in § 173.220(f) of this subchapter, the provisions of this subchapter do not apply to items of equipment such as fire extinguishers, compressed gas accumulators, airbag inflators and the like which are installed in the engine or machinery if they are necessary for the operation of the engine or machinery, or for the safety of its operator or passengers.
49 U.S.C. 5101-5128; 49 CFR 1.81 and 1.97.
The revisions and additions read as follows:
(d) * * *
(2) Service equipment must be configured or designed to prevent damage that could result in the release of the pressure receptacle contents during normal conditions of handling and transport. Manifold piping leading to shut-off valves must be sufficiently flexible to protect the valves and the piping from shearing or releasing the pressure receptacle contents. The filling and discharge valves and any protective caps must be secured against unintended opening. The valves must conform to ISO 10297:2014 Gas cylinders—Cylinder valves—Specification and type testing, or ISO 13340 (IBR, see § 171.7 of this subchapter) for non-refillable pressure receptacles, and be protected as specified in § 173.301b(f) of this subchapter. Until December 31, 2020, the manufacture of a valve conforming to the requirements in ISO 10297:2006 (IBR, see § 171.7 of this subchapter) is authorized. Until December 31, 2008, the manufacture of a valve conforming to the requirements in ISO 10297:1999 (IBR, see § 171.7 of this subchapter) is authorized.
(g) * * *
(4) ISO 9809-4:2014 Gas cylinders—Refillable seamless steel gas cylinders—Design, construction and testing—Part 4: Stainless steel cylinders with an Rm value of less than 1 100 MPa (IBR, see § 171.7 of this subchapter).
(h)
(k) * * *
(2) The porous mass in an acetylene cylinder must conform to ISO 3807:2013: Gas cylinders—Acetylene cylinders—Basic requirements and type testing (IBR, see § 171.7 of this subchapter). Until December 31, 2020, the manufacture of a cylinder conforming to the requirements in ISO 3807-2: Cylinders for acetylene—Basic requirements—Part 2: Cylinders with fusible plugs (IBR, see § 171.7 of this subchapter) is authorized.
(l)
(i) ISO 11119-1:2012 Gas cylinders—Refillable composite gas cylinders and tubes—Design, construction and testing—Part 1: Hoop wrapped fibre reinforced composite gas cylinders and tubes up to 450 l (IBR, see § 171.7 of this subchapter). Until December 31, 2020, cylinders conforming to the requirements in ISO 11119-1(E), Gas cylinders—Gas cylinders of composite construction—Specification and test methods—Part 1: Hoop-wrapped composite gas cylinders, First edition, May 2002 (IBR, see § 171.7 of this subchapter) are authorized.
(ii) ISO 11119-2:2012 Gas cylinders—Refillable composite gas cylinders and tubes—Design, construction and testing—Part 2: Fully wrapped fibre reinforced composite gas cylinders and tubes up to 450 l with load-sharing metal liners (including Amendment 1:2014) (IBR, see § 171.7 of this subchapter). Until December 31, 2020, cylinders conforming to the requirements in ISO 11119-2(E), Gas cylinders—Gas cylinders of composite construction—Specification and test methods—Part 2: Fully wrapped fibre reinforced composite gas cylinders with load-sharing metal liners, First edition, May 2002 (IBR, see § 171.7 of this subchapter) are authorized.
(iii) ISO 11119-3:2013 Gas cylinders—Refillable composite gas cylinders and tubes—Design, construction and testing—Part 3: Fully wrapped fibre reinforced composite gas cylinders and tubes up to 450 l with non-load-sharing metallic or non-metallic liners (IBR, see § 171.7 of this subchapter). Until December 31, 2020, cylinders conforming to the requirements in ISO 11119-3(E), Gas cylinders of composite construction—Specification and test methods—Part 3: Fully wrapped fibre reinforced composite gas cylinders with non-load-sharing metallic or non-metallic liners, First edition, September 2002, (IBR, see § 171.7 of this subchapter) are authorized.
(iv) ISO 11515:2013 Gas cylinders—Refillable composite reinforced tubes of water capacity between 450 L and 3000 L—Design, construction and testing (IBR, see § 171.7 of this subchapter).
(2) ISO 11119-2 and ISO 11119-3 gas cylinders of composite construction manufactured in accordance with the requirements for underwater use must bear the “UW” mark.
(o) * * *
(2) ISO 11114-2:2013 Gas cylinders—Compatibility of cylinder and valve materials with gas contents—Part 2: Non-metallic materials (IBR, see § 171.7 of this subchapter).
(q) * * *
(20) For composite cylinders and tubes having a limited design life, the letters “FINAL” followed by the design life shown as the year (four digits) followed by the month (two digits) separated by a slash (
(21) For composite cylinders and tubes having a limited design life greater than 15 years and for composite cylinders and tubes having non-limited design life, the letters “SERVICE” followed by the date 15 years from the date of manufacture (initial inspection) shown as the year (four digits) followed by followed by the month (two digits) separated by a slash (
(r)
(1) The top grouping contains manufacturing marks and must appear consecutively in the sequence given in paragraphs (q)(13) through (19) of this section.
(2) The middle grouping contains operational marks described in paragraphs (q)(6) through (11) of this section.
(3) The bottom grouping contains certification marks and must appear consecutively in the sequence given in paragraphs (q)(1) through (5) of this section.
(d) * * *
(3) * * *
(iv) ISO 9809-4:2014 Gas cylinders—Refillable seamless steel gas cylinders—Design, construction and testing—Part 4: Stainless steel cylinders with an Rm value of less than 1 100 MPa (IBR, see § 171.7 of this subchapter).
(f) A venting device must be fitted to Flexible Bulk Containers intended to transport hazardous materials that may develop dangerous accumulation of gases within the Flexible Bulk Container. Any venting device must be designed so that external foreign substances or the ingress of water are prevented from entering the Flexible Bulk Container through the venting device under conditions normally incident to transportation.
49 U.S.C. 5101-5128; 49 CFR 1.81 and 1.97.
(c)
(1) Each cylinder that is requalified in accordance with the requirements specified in this section must be marked in accordance with § 180.213, or in the case of a CRC, BTC, CTC or TC cylinder, in accordance with the requirements of the Transport Canada TDG Regulations.
(2) Each cylinder that fails requalification must be:
(i) Rejected and may be repaired or rebuilt in accordance with § 180.211 or § 180.212, as appropriate; or
(ii) Condemned in accordance with paragraph (i) of this section.
(3) For DOT specification cylinders, the marked service pressure may be changed upon approval of the Associate Administrator and in accordance with written procedures specified in the approval.
(4) For a specification 3, 3A, 3AA, 3AL, 3AX, 3AXX, 3B, 3BN, or 3T cylinder filled with gases in other than Division 2.2, from the first requalification due on or after December 31, 2003, the burst pressure of a CG-1, CG-4, or CG-5 pressure relief device must be at test pressure with a tolerance of plus zero to minus 10%. An additional 5% tolerance is allowed when a combined rupture disc is placed inside a holder. This requirement does not apply if a CG-2, CG-3 or CG-9 thermally activated relief device or a CG-7 reclosing pressure valve is used on the cylinder.
(d) * * *
(3) Dissolved acetylene UN cylinders: Each dissolved acetylene cylinder must be requalified in accordance with ISO 10462:2013 Gas cylinders—Acetylene cylinders—Periodic inspection and maintenance (IBR, see § 171.7 of this subchapter). Until December 31, 2018 requalification may be done in accordance with ISO 10462 (E), Gas cylinders—Transportable cylinders for dissolved acetylene—Periodic inspection and maintenance, Second edition, February 2005 (IBR, see § 171.7 of this subchapter). The porous mass and the shell must be requalified no sooner than 3 years, 6 months, from the date of manufacture. Thereafter, subsequent requalifications of the porous mass and shell must be performed at least once every ten years.
(a) * * *
(1) * * *
(iii) A repair, as defined in § 180.403, of a DOT specification cargo tank used for the transportation of hazardous materials in the United States may be performed by a facility in Canada in accordance with the Transport Canada TDG Regulations (IBR, see § 171.7 of this subchapter) provided:
(A) The facility holds a valid Certificate of Authorization from a provincial pressure vessel jurisdiction for repair;
(B) The facility is registered in accordance with the Transport Canada TDG Regulations to repair the corresponding TC specification; and
(C) All repairs are performed using the quality control procedures used to obtain the Certificate of Authorization.
(b)
(g) * * *
(1) The shell is inspected for pitting, corrosion, or abrasions, dents, distortions, defects in welds or any other conditions, including leakage, that might render the portable tank unsafe for transportation. The wall thickness must be verified by appropriate measurement if this inspection indicates a reduction of wall thickness;
Bureau of Safety and Environmental Enforcement (BSEE), Interior.
Final rule.
The Bureau of Safety and Environmental Enforcement (BSEE) is amending and updating the regulations regarding oil and natural gas production safety on the Outer Continental Shelf (OCS) by addressing issues such as: Safety and pollution prevention equipment design and maintenance, production safety systems, subsurface safety devices, and safety device testing. The rule differentiates the requirements for operating dry tree and subsea tree production systems and divides the current BSEE regulations regarding oil and gas production safety systems into multiple sections to make the regulations easier to read and understand. The changes in this rule are necessary to improve human safety, environmental protection, and regulatory oversight of critical equipment involving production safety systems.
This rule becomes effective on November 7, 2016. Compliance with certain provisions of the final rule, however, will be deferred until the times specified in those provisions and as described in part II.E of this document.
The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of November 7, 2016.
Amy White, BSEE, Office of Offshore Regulatory Programs, Regulations Development Section, at 571-230-2475 or at
This rule amends and updates BSEE's regulations for oil and gas production safety systems. The regulations (30 CFR part 250, subpart H) have not, until now, undergone a major revision since they were first published in 1988. Since that time, much of the oil and gas production on the OCS has moved into deeper waters and the regulations have not kept pace with the technological advancements.
These regulations address issues such as production safety systems, subsurface safety devices, safety device testing, and production processing systems and areas. These systems play a critical role in protecting workers and the environment. In this final rule, BSEE has made the following changes to subpart H:
• Restructured subpart H to have shorter, easier-to-read sections and clearer, more descriptive headings.
• Updated and improved safety and pollution prevention equipment (SPPE) design, maintenance, and repair requirements in order to increase the overall level of certainty that this equipment will perform as intended, including in emergency situations.
• Expanded the regulations to differentiate the requirements for operating dry tree and subsea tree production systems on the OCS.
• Incorporated by reference new industry standards and update the previous partial incorporation of other standards to require compliance with the complete standards.
• Added new requirements for firefighting systems, shutdown valves and systems, valve closure and leakage, and high pressure/high temperature (HPHT) well equipment.
• Rewrote the subpart in plain language.
In addition to revising subpart H, we are revising the existing regulation (§ 250.107(c)) that requires the use of best available and safest technology (BAST) to follow more closely the Outer Continental Shelf Lands Act's (OCSLA, or the Act) statutory language regarding BAST.
OCSLA, 43 U.S.C. 1331
The Secretary delegated most of the responsibilities under OCSLA to BSEE and the Bureau of Ocean Energy Management (BOEM), both of which are charged with administering and regulating aspects of the Nation's OCS oil and gas program. BSEE and BOEM work to promote safety, protect the
BSEE frequently uses standards (
Federal regulations, at 1 CFR part 51, govern how BSEE and other Federal agencies incorporate documents by reference. Agencies may incorporate a document by reference by publishing in the Federal Register the document title, edition, date, author, publisher, identification number, and other specified information. The preamble of the final rule must also discuss the ways that the incorporated materials are reasonably available to interested parties and how those materials can be obtained by interested parties. The Director of the Federal Register will approve each incorporation of a publication by reference in a final rule that meets the criteria of 1 CFR part 51.
When a copyrighted publication is incorporated by reference into BSEE regulations, BSEE is obligated to observe and protect that copyright. BSEE provides members of the public with Web site addresses where these standards may be accessed for viewing—sometimes for free and sometimes for a fee. Standards development organizations decide whether to charge a fee. One such organization, the American Petroleum Institute (API), provides free online public access to review its key industry standards, including a broad range of technical standards. All API standards that are safety-related and all API standards that are incorporated into Federal regulations are available to the public for free viewing online in the Incorporation by Reference Reading Room on API's Web site. Several of those standards are incorporated by reference in this final rule (as described in parts II.C and IV of this document). In addition to the free online availability of these standards for viewing on API's Web site, hardcopies and printable versions are available for purchase from API. The API Web site address is:
For the convenience of members of the viewing public who may not wish to purchase or view these incorporated documents online, they may be inspected at BSEE's office, 45600 Woodland Road, Sterling, Virginia 20166, or by sending a request by email to
BSEE's regulations require operators to design, install, use, maintain, and test production safety equipment to ensure safety and the protection of the human, marine, and coastal environments.
• Conform to OCSLA, as amended, its applicable implementing regulations, lease provisions and stipulations, and other applicable laws;
• Are safe;
• Conform to sound conservation practices and protect the rights of the U.S. in the mineral resources of the OCS;
• Do not unreasonably interfere with other uses of the OCS; and
• Do not cause undue or serious harm or damage to the human, marine, or coastal environments. (
Typically, well completions associated with offshore production platforms are characterized as either dry tree (surface) or subsea tree completions. The “tree” is the assembly of valves, gauges, and chokes mounted on a well casing head and used to control the production and flow of oil or gas. Dry tree completions are typical for OCS shallow water production platforms, with the tree in a “dry” state located on the deck of the production platform. The dry tree arrangement allows direct access to valves and gauges to monitor well conditions, such as pressure, temperature, and flow rate, as well as direct vertical well access. Dry tree completions are easily accessible. Because of their easy accessibility, even as oil and gas production moved into deeper water, dry trees were still used on new types of production platforms more suitable for deeper water, such as compliant towers, tension-leg platforms (TLPs), and spars. These platform types gradually extended the depth of usage for dry tree completions to over 4,600 feet of water depth.
Production in the Gulf of Mexico (GOM) now occurs in depths of 9,000 feet of water, however, with many of the wells producing from water depths greater than 4,000 feet utilizing “wet” or subsea trees. Subsea tree completions are done with the tree located on the seafloor. These subsea completions are generally tied back to floating production platforms, and from there the production moves to shore through pipelines. Due to the location on the seafloor, subsea trees or subsea completions do not allow for direct access to valves and gauges, but the pressure, temperature, and flow rate from the subsea location is monitored from the production platform and, in some cases, from onshore data centers.
In conjunction with all production operations and completions, including both wet and dry trees, there are associated subsurface safety devices designed to prevent uncontrolled releases of reservoir fluid or gas.
Most of the current regulatory requirements for production safety systems are contained in subpart H of part 250 of BSEE's existing regulations (existing §§ 250.800 through 250.808). Revision of those requirements is the primary focus of this rulemaking.
The existing regulations on production safety systems that this final rule is amending were first published on April 1, 1988. (
As discussed in part I.C of this document, subsea trees and other technologies have evolved, and their use has become more prevalent offshore, over the last 28 years, especially as more and more production has shifted from shallow waters to deepwater environments. This includes significant developments in production-related areas as diverse as foam firefighting systems; electronic-based emergency shutdown (ESD) systems; subsea pumping, waterflooding, and gas lift; and new alloys and equipment for high temperature and high pressure wells. The subpart H regulations, however, have not kept pace with those developments.
On August 22, 2013, BSEE published a Notice of Proposed Rulemaking (the proposed rule) in the
The comment period for the proposed rule was originally set to close on October 21, 2013. However, in response to several requests, BSEE published a notice on September 27, 2013 (78 FR 59632), extending the comment period until December 5, 2013.
As discussed in part IV.C of this document, BSEE received 57 separate written comments on the proposed rule from a variety of interested stakeholders (
After the close of the comment period, BSEE subject matter experts and decision-makers carefully considered all of the relevant comments in developing this final rule. In part IV of this document, BSEE responds to those comments and discusses how several provisions of the proposed rule were revised in this final rule to address concerns or information raised by commenters.
As a result of BSEE's consideration of all the relevant comments and other relevant information, BSEE has developed this final rule, which is intended to improve worker safety and protection of marine and coastal ecosystems by helping to reduce the number of production-related incidents resulting in oil spills, injuries, and fatalities.
Among other significant changes to the existing regulations, this final rule establishes new requirements for the design, testing, maintenance, and repair of SPPE, using a lifecycle approach. The lifecycle approach involves careful consideration and vigilance throughout SPPE design, manufacture, operational use, maintenance, and decommissioning of the equipment. It is a tool for continual improvement throughout the life of the equipment. The lifecycle approach for SPPE is not a new concept, and its elements are discussed in several industry documents already incorporated by reference in the existing regulations (
BSEE's focus in the development of this rule has been, and will continue to be, improving worker safety and protection of the environment by helping to reduce the number of production-related incidents resulting in oil spills, injuries and fatalities. For example, there have been multiple incidents, including fatalities, injuries, and facility damage related to the mechanical integrity of the fire tube for tube-type heaters. BSEE is aware that this type of equipment has not been regularly maintained by industry. In the final rule, BSEE is requiring that this type of equipment be removed and inspected, and then repaired or replaced as needed, every 5 years. This requirement will improve equipment reliability to help limit incidents associated with the mechanical integrity of the fire tubes.
Three existing NTLs are directly related to issues addressed in this rulemaking:
• NTL No. 2011-N11,
• NTL No. 2009-G36,
• NTL No. 2006-G04,
Most of the elements from these NTLs are codified in this final rule. After the final rule is effective, BSEE intends to rescind these NTLs and remove them from the
BSEE is incorporating by reference one new standard in the final rule, API 570, Piping Inspection Code: In-service Inspection, Rating, Repair, and Alteration of Piping Systems, Third Edition, November 2009. As discussed in the standard, API 570 covers inspection, rating, repair, and alteration procedures for metallic and fiberglass-reinforced plastic piping systems and their associated pressure relieving devices that have been placed in service. The intent of this code is to specify the in-service inspection and condition-monitoring program that is needed to determine the integrity of piping systems. That program should provide reasonably accurate and timely assessments to determine if any changes in the condition of piping could compromise continued safe operation. It is also the intent of this code that owners/users respond to any inspection results that require corrective actions to assure the continued integrity of piping consistent with appropriate risk analysis. Items discussed in this standard include inspection plans, condition monitoring methods, pressure testing of piping systems, and inspection recommendations for repair or replacement.
The other standards referred to in this final rule are already incorporated by
• BSEE is incorporating a more recently reaffirmed version of American National Standards Institute (ANSI)/API Spec. 6AV1, Specification for Verification Test of Wellhead Surface Safety Valves and Underwater Safety Valves for Offshore Service, First Edition, February 1996; Reaffirmed April 2008. This standard includes the minimum acceptable standards for verification testing of surface safety valves (SSVs)/underwater safety valves (USVs) for two performance requirement levels.
• BSEE is also incorporating a more recently reaffirmed version of ANSI/API Spec. 14A, Specification for Subsurface Safety Valve Equipment, Eleventh Edition, October 2005, Reaffirmed June 2012. This standard provides the minimum acceptable requirements for subsurface safety valves (SSSVs), including all components that establish tolerances and/or clearances that may affect performance or interchangeability of the SSSVs. It includes repair operations and the interface connections to the flow control or other equipment, but does not cover the connections to the well conduit.
• BSEE is incorporating a recently reaffirmed version of API RP 14E, Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems, Fifth Edition, October 1991; Reaffirmed January 2013. This standard provides minimum requirements and guidelines for the design and installation of new piping systems on production platforms located offshore. This document covers piping systems with a maximum design pressure of 10,000 pounds per square inch gauge (psig) and a temperature range of −20 degrees to 650 degrees Fahrenheit.
• BSEE is incorporating a more recently reaffirmed version of API RP 14F, Recommended Practice for Design, Installation, and Maintenance of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class 1, Division 1 and Division 2 Locations, Fifth Edition, July 2008, Reaffirmed April 2013. This RP sets minimum requirements for the design, installation, and maintenance of electrical systems on fixed and floating petroleum facilities located offshore. This RP is not applicable to mobile offshore drilling units (MODUs) without production facilities. This document is intended to bring together in one place a brief description of basic desirable electrical practices for offshore electrical systems. The RP recognizes that special electrical considerations exist for offshore petroleum facilities, including inherent electrical shock, space limitations, corrosive marine environment, and motion and buoyancy concerns.
• BSEE is incorporating a recently reaffirmed version of API RP 14J, Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities, Second Edition, May 2001; Reaffirmed January 2013. This standard assembles into one document useful procedures for planning, designing, and arranging offshore production facilities, and performing a hazards analysis on open-type offshore production facilities.
• BSEE is incorporating a more recently reaffirmed version of ANSI/API Spec. Q1, Specification for Quality Programs for the Petroleum, Petrochemical and Natural Gas Industry, Eighth Edition, December 2007, Addendum 1, June 2010. This standard states that the adoption of a quality management system should be a strategic decision of any organization. The design and implementation of an organization's quality management system is influenced by its organizational environment, its varying needs, its particular objectives, the product it provides, and its size and organizational structure.
In addition, this rule incorporates API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2, Second Edition, November 1997, Reaffirmed November 2002. The purpose of this RP is to provide guidelines for classifying locations at petroleum facilities as Class I, Division 1 and Class I, Division 2 for the selection and installation of electrical equipment.
After consideration of all relevant comments, BSEE made a number of revisions to the proposed rule language in the final rule. We are highlighting several of these changes here because they are significant, and because multiple comments addressed these topics. A discussion of the relevant comments, including BSEE's specific responses, is found in part IV of this document. All of the revisions to the proposed rule language made after consideration of relevant comments are explained in more detail in that part. The significant revisions made in response to comments include:
BSEE proposed to revise the BAST provisions in existing § 250.107 in order to align the regulatory language more closely with the statutory BAST language in OCSLA, to clarify BSEE's expectations, and to make it easier for operators to understand when they must use BAST. BSEE proposed to delete existing paragraph (d) (regarding authority of the Director to impose additional BAST measures) and to revise paragraph (c) to include more of the statutory language and to provide an exception from use of BAST when an operator demonstrates that the incremental benefits of using BAST are insufficient to justify its incremental costs.
BSEE received numerous comments on this proposed change. Among other issues, some commenters stated that the proposed language failed to confirm BSEE's prior position regarding compliance with BSEE's regulations being considered the use of BAST. As explained in more detail in part IV.C of this document, after consideration of the comments and further deliberation, BSEE has revised and reorganized final § 250.107(c) to address many of these issues. The revised language clarifies BSEE's position that compliance with existing regulations is presumed to be use of BAST until (and unless) the Director makes a specific BAST determination that other technology is required. The final rule also provides that the Director may waive the requirement to use BAST on a category of existing operations if the Director determines that use of BAST by that category of existing operations would not be practicable. In addition, the revised language provides a clear path for an operator of an existing facility to request a waiver from use of BAST if the operator demonstrates, and the Director determines, that use of BAST would not be practicable. These revisions are consistent with the statutory language and intent of OCSLA, and will further clarify for operators when use of BAST is or is not required and when that requirement may be waived.
BSEE proposed to revise the firewater systems requirements for both open and totally enclosed platforms. Among other things, BSEE proposed requiring that the firefighting systems conform to API RP 14G, Recommended Practice for Fire Prevention and Control on Fixed Open-type Offshore Production Platforms. This proposed requirement was in addition to existing § 250.803(b)(8),
BSEE understands that there are many different types of firefighting systems discussed in API RP 14G. Accordingly, in this final rule, BSEE has revised proposed § 250.859(a) to require compliance with the firewater system sections of API RP 14G. This change will clarify BSEE's expectations for compliance with this industry standard. This change will also enhance the overall firewater system operability by requiring compliance with provisions in API RP 14G (
BSEE also made other changes to the proposed § 250.859. Specifically, as suggested by several commenters, we clarified the firefighting requirements to minimize confusion regarding U.S. Coast Guard (USCG) jurisdiction and to separate the firewater requirements for fixed facilities and floating facilities. In particular, we revised § 250.859(a) in the final rule to include requirements for firefighting systems on “fixed facilities,” and added final paragraph (b) to clarify the requirements for firefighting systems on floating facilities. Final § 250.859(b) also clarifies that the firewater system must protect all areas where production-handling equipment is located, that a fixed water spray system must be installed in enclosed well-bay areas where hydrocarbon vapors may accumulate, and that the firewater system must conform to the USCG requirements for firefighting systems on floating facilities.
BSEE received a number of comments on proposed §§ 250.851(b), 250.852(a), 250.858(b), and 250.865(b), regarding the operating pressure ranges for certain types of equipment, including the pressure safety high and low set points. As discussed in the proposed rule, pressure recording devices must be used to establish the new operating pressure ranges for specific equipment (
BSEE is requiring the operating pressure ranges because we are aware that not all operators monitor how the pressure regimes are changing. Nonetheless, to help prevent nuisance shut-ins, the final rule allows operators to use a more conservative approach by resetting the operating pressure at an operating range that is lower than the specified change in pressure. To clarify how a new operating pressure range can be established, BSEE added language to the appropriate locations in final §§ 250.851, 250.852, 250.858, and 250.865 stating that once system pressure has stabilized, pressure recording devices must be used to establish new operating pressure ranges. The revised language also clarifies that the pressure recording devices must document the pressure range over time intervals that are no less than 4 hours and no more than 30 days long. Establishing new operating ranges based on these parameters will help prevent nuisance shut-ins, by basing the shut-in set points on an identified, stabilized baseline. BSEE also added a minimum time provision to each of these final provisions to ensure that the system pressure is stable before setting the operating ranges. The time interval limits were set, in part, because pressure spikes and/or surges may not be discernable in a range chart if the run time is too long.
In proposed § 250.855, BSEE retained the ESD requirements from § 250.803(b)(4) in the existing regulations, and clarified that the breakable loop in the ESD system is not required to be physically located on the facility's boat landing; however, in all instances, the breakable loop must be accessible from a vessel adjacent to or attached to the facility. A commenter expressed concern that the proposed rule referenced only pneumatic-type valves, while current technology incorporates electronic switching devices.
After considering the issues raised in the comment and reviewing current technology, BSEE has revised proposed § 250.855(a) in the final rule to provide that electric ESD stations should be wired as “de-energize to trip” or as supervised circuits. Since BSEE is now allowing electric ESD switches, BSEE wants to ensure that ESD equipment is fully functional, because the key role of the ESD system is to shut-in the facility in an emergency. Therefore, BSEE also added new language clarifying that all ESD components should be of high quality and corrosion resistant, and that ESD stations should be uniquely identified. These revisions are necessary to help ensure that these newer types of ESD stations function properly and to assist personnel in recognizing the ESD location for activation in an emergency.
In addition to the differences between the proposed and final rules discussed here and in part IV, BSEE also made minor changes to the proposed rule language in response to comments suggesting that BSEE eliminate redundancy, clarify potentially confusing language, streamline the regulatory text, or align the language in the rule more closely with accepted industry terminology. BSEE also made other revisions to this final rule to correct grammatical or clerical errors, eliminate ambiguity, and further clarify the intent of the proposed language.
The final rule is effective on November 7, 2016. However, BSEE has deferred the compliance dates for certain provisions of the final rule until the times specified in those provisions and as discussed in more detail in part IV of this document.
Compliance with § 250.801(a)(2) for requirements related to boarding shutdown valves (BSDVs) and their actuators as SPPE is deferred until September 7, 2017.
Compliance with § 250.851(a)(2), regarding District Manager approval of existing uncoded pressure and fired vessels that are not code stamped according to ANSI/American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, is deferred until March 1, 2018.
Compliance with the elements of § 250.859(a)(2) requiring all new firewater pump drivers to be equipped
The final rule restructures the provisions of existing subpart H. The new regulations are divided into shorter, easier-to-read sections. These sections are more logically organized, as each section focuses on a single topic instead of multiple topics, as found in each section of the existing regulations. To assist in understanding the revised subpart H regulations, the following table shows how sections of the final rule correspond to the provisions in former subpart H:
In response to the proposed rule, BSEE received 57 separate sets of comments from individual entities (companies, industry organizations, or private citizens). (One comment included 1,527 individual letters, as an attachment, although the content of all of these letters was substantially the same.) Some entities submitted comments multiple times. All comments are posted at the
In addition to the comments on all provisions of the proposed rule, BSEE solicited comments on certain issues related to those proposed provisions, including:
• Organization of the rule based on use of subsea trees and dry trees;
• Lifecycle approach to other types of critical equipment, such as blowout preventers (BOPs);
• Failure Reporting and Information Dissemination; and
• Third-party Certification Organizations.
BSEE also solicited comments and requested information on other topics that were indirectly related to, but outside the specific scope of, this rulemaking. These topics included:
• Opportunities to limit emissions of natural gas from OCS production equipment; and
• Opportunities to limit flaring of natural gas.
BSEE requested comments on natural gas emissions and flaring to inform future policies and potential rulemakings. Since the information provided in response to these topics is not directly related to, and was not considered in developing, this final rule, we have not discussed those comments or information in this document.
In addition to comments on specific provisions of the proposed rule, various commenters raised more general issues, including:
• Extension of the public comment period;
• BSEE and USCG jurisdiction; and
• Arctic production safety systems.
The following is a summary of, and BSEE's responses to, comments on these topics. BSEE's responses to more specific comments on proposed provisions are addressed in the “Section-by-Section” discussion in part IV.C of this document.
BSEE received a number of comments requesting an extension of the public comment period. In response to these requests, BSEE extended the public comment period by 45 days. Some commenters also requested that BSEE hold a public workshop on the proposed rule.
BSEE determined that the extension of the public comment period was sufficient for the public to review, understand, and comment on the proposed rule and thus, that a workshop was not necessary. In addition, BSEE determined that a public workshop would result in significant delays in developing and publishing a final rule, which would also delay the improvements in safety and environmental protection intended by the final rule with no commensurate benefits to justify that delay.
BSEE received comments on a number of provisions in the proposed rule expressing concerns that BSEE was reaching beyond its authority and trying to regulate activities that are under USCG jurisdiction. Both BSEE and the USCG have jurisdiction over different aspects and components of oil and gas production safety systems. These regulations apply only to operations that are under BSEE authority. OCSLA directs that the Secretary prescribe regulations necessary to provide that OCS operations are “conducted in a safe manner by well-trained personnel using technology, precautions, and techniques sufficient to prevent or minimize the likelihood of blowouts, loss of well control, fires, spillages,. . . or other occurrences which may cause damage to the environment or to property, or endanger life or health.” (43 U.S.C. 1332(6).) Those regulations apply to all operations conducted under an OCS lease. (43 U.S.C. 1334(a).)
To promote interagency consistency in the regulation of OCS activities, and to describe the agencies' respective and cooperative roles, BSEE and USCG have signed formal memoranda of understanding (MOUs) and memoranda of agreement (MOAs). Those memoranda recognize that, in many respects, BSEE and USCG share responsibility and authority over various aspects of safety and environmental protection related to oil and gas operations on the OCS. The memoranda reflect that BSEE has, and exercises, authority to regulate safety and environmental functions related to OCS facilities, including: developing regulations governing OCS operations, permitting, conducting inspections and investigations, enforcing regulatory requirements, and overseeing oil spill response planning and preparedness. Similarly, the memoranda reflect USCG's authority to regulate the safety of life, property, and navigation and protection of the environment on OCS units and vessels engaged in OCS activities, as well as its authority to regulate workplace safety and health, workplace activities, conditions and equipment on the OCS, and oil spill preparedness and response.
The various memoranda are intended to minimize duplication of effort and promote consistency of regulations and policies where shared responsibilities exist (including, for example, issues related to both fixed and floating facilities) but do not limit either agency's statutory authorities and responsibilities. The USCG-BSEE memoranda are available on BSEE's Web site at:
Numerous comments were submitted regarding BSEE and USCG jurisdiction in connection with multiple sections within the rule. Some comments cited jurisdictional concerns as a general reason why a section should not have been included in the proposed rule. Other commenters expressly noted concern that BSEE's crossing of jurisdictional lines with the USCG could lead to confusion or result in regulatory burdens on the operators. These commenters noted that the USCG has its own rules that govern all or portions of pressurized vessels and fixed and floating facilities. All of the comments that discussed USCG's rules asserted that BSEE lacked some degree of authority concerning the regulation of production safety systems under OCSLA.
Commenters also raised issues concerning BSEE's authority with regard to distinctions between floating and fixed platforms. Commenters described BSEE's authority as limited to fixed platforms and, due to that limitation, they asserted that BSEE does not have the authority to regulate issues regarding floating facilities. These issues were often raised with regard to specific provisions, such as §§ 250.861, Foam firefighting systems, and 250.862, Fire and gas-detection systems.
Some comments raised jurisdictional issues regarding sections of the proposed rule dealing with certain technical or safety matters that the commenters asserted are within USCG's area of expertise (
BSEE does not agree with the comments suggesting that the provisions in the proposed rule are outside of BSEE's jurisdiction. This rulemaking applies to production operations that BSEE has historically regulated under longstanding regulations consistent with the authority granted by OCSLA to the Secretary and subsequently delegated to BSEE. This final rule is consistent with the USCG-BSEE MOAs and MOUs. Nothing in the USCG-BSEE MOAs or
A number of comments requested that BSEE add specific production safety requirements for the Arctic OCS environment to the final rule.
BSEE does not agree that new Arctic-specific provisions, which were not included in the proposed rule, should be added to this final rule. Prior to approval by BSEE, all proposed oil and gas production operations on the OCS, including in the Arctic, are required to have production safety equipment that is designed, installed, operated, and tested specifically for the surrounding location and environmental conditions of operation. In particular, the existing BSEE regulations (retained in relevant part by this final rule) require that production safety system equipment and procedures for operations conducted in subfreezing climates take into account floating ice, icing, and other extreme environmental conditions that may occur in the area. (
This discussion summarizes: all of the regulatory sections in the final rule; specific comments submitted, if any, on each section in the proposed rule; and BSEE's responses to those comments, including whether BSEE made any revisions to the proposed regulatory text in this final rule in response to the comments. The comments and BSEE's responses are organized as follows: General Comments; Economic Analysis Comments; and Section-by-Section Summary and Responses to Comments.
BSEE received public comments on the following general issues related to the proposed rule that were not specific to any proposed requirement.
Comment—Commenters asserted that, by including so many third-party certifications of equipment and processes in the proposed rule, BSEE is implying that other proposed requirements that do not call for certifications are somehow less important.
Response—All of the provisions in this final rule are important. The certifications required by this rule are just one tool that BSEE uses to help ensure that operators meet the level of safety and environmental protection mandated under OCSLA. Other provisions of this rule also help meet that mandate through requirements placed directly on the operators.
Comment—Commenters asserted that the rule does not ensure operator qualification requirements for staff responsible for operating the offshore production facility. They suggested that each company permitted to conduct offshore production facility operations should have a written operator qualification program. They recommended that programs should include, at a minimum, an evaluative procedure (including reevaluation as appropriate), explicit reasons why individuals no longer would be qualified, and record-keeping requirements.
Response—BSEE does not agree that any such requirements should be added to this final rule. Operator personnel qualifications are already addressed in the Safety and Environmental Management System (SEMS) regulations in part 250, subpart S, specifically § 250.1915, What training criteria must be in my SEMS program?
Comment—A commenter asserted that BSEE needs to ensure that the proposed subpart H changes align with the requirements of existing regulations in subparts J, S, I, and O, as well as with the regulatory requirements of other agencies (
Response—BSEE does not agree with the suggestion that this final rule conflicts with or contradicts any other provision in BSEE's regulations. There may be overlapping requirements in the various subparts, however, BSEE does not agree that there are conflicts. If there is a need for additional clarity, BSEE will issue guidance in the future. For example, the suggestion that the BSDV requirements in proposed subpart H conflict with BSDV requirements in existing subpart J is incorrect. Subpart H applies to any piping downstream of the BSDV, while subpart J's requirements apply to piping upstream of the BSDV. Similarly, the stationkeeping design requirements for floating production facilities in final § 250.800(c)(3) refer to API RP 2SK and API RP 2SM, which are also incorporated by reference in the design requirements for platforms under § 250.901 of subpart I. While the commenter may consider this duplicative, including the same requirements in subpart H and subpart I ensures that the facilities are designed with the production systems in mind and helps prevent conflicts. While BSEE is not aware of any inconsistencies, BSEE will monitor implementation of this final rule to assess whether any confusion arises from any overlap between subpart H provisions and other BSEE regulations. BSEE will consider whether to address any such issues, if they arise, in possible future rulemakings or guidance.
Finally, as previously discussed, this final rule is aligned with the responsibilities and regulations of the USCG.
Comment—Commenters asserted that the proposed regulations were not clear with respect to the impact of the requirements on existing equipment (such as non-certified SPPE, BSDVs and single bore production risers) that is fit for purpose and performing satisfactorily within the established operating window and design conditions.
Response—BSEE does not agree that the proposed rule was unclear as to any potential impacts on existing equipment. BSEE considered the impact on existing equipment designs when specifying the effective dates for new provisions and determined whether and when it is appropriate for new requirements to apply to existing equipment. For example, most existing SPPE is already certified under the existing regulations; this final rule adds a requirement for certification of BSDVs and their actuators, beginning 1 year after publication of the final rule. Also, under the final rule, operators may continue to use existing SPPE, such as BSDVs. However, if a BSDV fails or does not meet the applicable requirements (
Similarly, under final § 250.800(c)(2), operators may continue to use single bore production risers that are already installed on floating production systems, although they cannot install new single bore production risers on floating productions systems after the effective date of this final rule (as explained further in part IV.C). However, for already-installed single bore production risers, additional precautions are necessary for wear protection, wear measurement, fatigue analysis, and pressure testing to perform any well operations with the tree removed. This is consistent with established BSEE policy and approvals for well operations using single bore production risers.
Comment—A commenter asserted that the Pew Charitable Trusts' September 2013 Arctic Standards Report identified a number of improvements that could be made in BSEE's regulations. The commenter requested that BSEE review and incorporate specific sections of this report related to the subpart H rulemaking.
Response—BSEE reviewed the information provided in the Pew Arctic report, which only addresses Arctic operations. This rulemaking, however, applies to production operations in all OCS regions; the requirements are not specific to one area of the OCS. As previously mentioned, the existing BSEE regulations already require that production safety system equipment and procedures for operations located in subfreezing climates take into account floating ice, icing, and other extreme environmental conditions that may occur in the area. This final rule does not change that requirement. The sections of the report the commenter cited are outside the scope of this rulemaking and address matters not proposed for public notice and comment through the proposed rule.
BSEE received public comments on the following issues related to the initial economic analysis for the proposed rule and the economic analysis summary in the proposed rule.
Comment—A commenter asserted that the initial economic analysis did not reflect the extensive facility modifications that the proposed rule would trigger. The commenter asserted that the agency failed to consider the economic impact of codifying numerous NTLs and industry practices. One commenter specifically questioned the estimated impact on existing fire-fighting systems designed in accordance with the existing regulations and previously approved by BSEE.
Response—BSEE disagrees with the suggestion that we have underestimated the potential cost impacts of this rule. Many of the provisions in the proposed rule were based on existing policy and guidance contained in permit conditions and NTLs. NTLs provide guidance to operators on compliance with existing regulations. BSEE included any costs associated with existing regulatory policy and guidance and industry practices in the baseline of the economic analysis. As specified by Executive Order (E.O.) 12866 and Office of Management and Budget (OMB) Circular A-4, “Regulatory Analysis” (2003), which provides guidance to Federal agencies on the preparation of economic analyses, BSEE estimates the costs of a rule resulting from modifications or new provisions in the rule that cause changes from the baseline. Pursuant to OMB Circular A-4, the baseline represents the agency's best assessment of what the world would be like without the new rule. The baseline includes all practices that are already incorporated into industry or regulatory standards, and that would continue to exist even if the new rule were not adopted. For economic analysis purposes, we assume that operators are already following the published NTLs in order to comply with existing regulations; thus, there is no change in industry practices, and no additional costs, when such practices are codified in the regulations.
In particular, the requirements for the firefighting systems in the final rule are consistent with the requirements in the existing BSEE regulations. The costs for the chemical firefighting systems and the inspection and testing of foam in the foam firefighting systems are addressed in the final economic analysis for this rule.
Comment—A commenter asserted that the bureau failed to accurately determine the impacts on small businesses operating offshore and on those businesses supporting the offshore industry through services and equipment.
Response—In the Regulatory Flexibility Act (RFA) determination for this final rule (
As explained in the RFA discussion in part V, BSEE estimated that the total annual cost of the rule per small entity would be about $18,000, which BSEE determined is not a significant economic impact. More details about these estimates are in the RFA discussion in part V of this document.
Comment—A commenter asserted that, while the proposed rule is intended primarily to codify standard industry practice and clarify existing regulations, BSEE had not acknowledged the impact of the proposed rule on existing operations and that the initial economic analysis grossly underestimated the actual cost.
Response—BSEE disagrees with those comments. The initial economic analysis adequately addressed the significant new costs that BSEE anticipated at the time of the proposed rule. However, as explained in more detail in part V of this document, the final economic analysis includes several adjustments to the estimated costs of the final rule, based on comments on the proposed rule and on changes to existing practices that BSEE now expects will occur as a result of the final
Comment—A commenter asserted that the proposed rule did not discuss why the new requirements are necessary and asked what incidents may be avoided by the proposed requirements. The commenter noted that although the bureau did conduct a break-even analysis for the proposed rule, since the regulatory benefits are highly uncertain, neither the proposed rule notice nor the initial economic analysis discussed the regulatory benefits of the proposed rule.
Response—BSEE does not agree that the proposed rule did not explain why the proposed requirements were necessary. The preamble to the proposed rule adequately described the general and specific purposes of the proposal. (
Comment—One commenter questioned the initial economic analysis conclusion that there would only be a limited number of reports of design changes or modifications. The estimated labor for BSEE to work with this information is $68. Given this effort by BSEE to analyze the information, the commenter questioned how this new requirement will be of any value to BSEE.
Response—In BSEE's experience, design changes do not happen frequently; therefore, we do not anticipate very many reports based on this requirement (
Comment—A commenter questioned the accuracy of the estimated costs for marine construction in the initial economic analysis because the estimates did not include any costs (or the time) for transportation on the OCS.
Response—Although the commenter did not explain what it meant by “marine construction,” BSEE assumes it was referring to the cost of transportation on the OCS. BSEE does not agree that the total costs of transportation on the OCS should be included in the costs of the rule because operators can use regularly scheduled trips, coordinating with crew boats or helicopter trips, to achieve compliance with the final rule. There does not need to be a special, separate trip for this purpose. Moreover, trips to and from these facilities already occur frequently and are, therefore, part of the baseline. The costs for the petroleum technician, labor, shipping and materials are discussed in the final economic analysis.
Comment—A commenter asserted that BSEE overestimated the amount of spilled oil in the initial economic analysis, and that the estimate of 57 leakage occurrences appears too high. The commenter requested that a list of the incidents considered by BSEE be included in the response to comments in the final rulemaking.
Response—It appears that the commenter assumed that the oil spill volumes estimated in the initial analysis were related to the leakage occurrences. However, the oil spill estimate is not related to leakage incidents or leakage rates. Oil spill volumes refer to oil released into the environment. By contrast, the leakage occurrences refer to leaking SSSVs, which are part of a closed safety system, designed to minimize oil spills by stopping the flow within the tubing if the riser is damaged; thus, that oil is not released into the environment. Based on BSEE data for June 2003 through May 2013, BSEE issued a total of 57 Incidents of Noncompliance (INCs) associated with leakage rates (P-280) under the category of “Subsurface Safety Device Testing.”
Comment—Several commenters questioned the economic feasibility and impact of using BAST. They also asserted that the initial economic analysis failed to include any costs associated with the proposed revisions to § 250.107(c) and that those potential costs should have been estimated and analyzed in the economic analysis.
Response—This rule does not identify any technology as BAST and merely clarifies the regulatory language to be more in alignment with the statutory language. BSEE disagrees with the suggestions that the revisions to § 250.107(c) constitute either a BAST program or a BAST determination, and that those revisions will impose new costs on operators. As explained in more detail later in this document, the revisions to § 250.107(c) are intended to align the language of that paragraph more closely with the statutory language and intent of the BAST provision in OCSLA (43 U.S.C. 1347(b)). In fact, final § 250.107(c)(1) uses essentially the same language as the statutory provision, although the language in the final regulation is arranged so as to be more clear and easier to follow. Similarly, final § 250.107(c)(2) clarifies and confirms the longstanding principle, stated in former § 250.107(c), that conformance with BSEE regulations qualifies as the use of BAST, unless or until the BSEE Director makes a specific BAST determination that other technologies are required. Thus, since final paragraph (c)(1) merely incorporates and clarifies the statutory language, and paragraph (c)(2) clarifies and reconfirms the existing regulatory language and policy, those provisions do not impose any new BAST requirements or create a new BAST program.
The only arguably significant addition to existing § 250.107(c) is final paragraph (c)(3), which states that the Director may waive the requirement to use BAST for a category of existing operations if the Director determines that use of BAST by that category of existing operations would not be practicable, and that the Director may waive the use of BAST at an existing operation if the operator demonstrates, and the Director determines, that the use of BAST would not be practicable for that operation. However, paragraph (c) in the existing regulation already effectively provided for such an exception from the required use of BAST,
Comment—Another commenter asserted that there was no transparent process for identifying what technology qualifies as “BAST” and that, due to the lack of clarity and transparency on what would be required, the cost impact was grossly understated.
Response—BSEE disagrees with this comment. As stated in response to the prior comment, neither proposed nor final § 250.107(c) involves or affects BSEE's process for determining what specific technology is BAST. Revised § 250.107(c) only clarifies, on a non-technology-specific basis, when use of BAST is or is not required, and confirms that conformance with existing BSEE regulations is considered use of BAST unless and until the BSEE Director makes specific determinations that other technologies are BAST. Thus, as previously discussed, there are no costs associated with this section. Further, as several industry comments acknowledged, BAST is already an established part of BSEE regulations. Thus, since final § 250.107(c) is consistent with the statutory requirements of OCSLA and with existing § 250.107(c), any costs that might be attributable to the provision are part of the economic baseline. To the extent the commenter objects to, or wants to suggest improvements to, the process by which BSEE makes BAST determinations, the commenter may submit its views to BSEE. However, those views are beyond the scope of this rulemaking.
Comment—A commenter pointed out that the initial economic analysis did not include cost estimates for proposed § 250.800—General.
Response—BSEE disagrees with the suggestion that revised § 250.800 would impose new costs that should have been included in the economic analysis. That section of the final rule contains essentially the same requirements as existing § 250.800, except for new language added to proposed and final paragraph (c)(2) and new paragraph (d). The new language in paragraph (c)(2) prohibits the installation of new single bore production risers. However, there are no new costs resulting from this new language because BSEE has not approved installation of any new single bore production riser for the last 8 years; BSEE has only approved installation of dual bore risers over that time, and this now represents standard and longstanding industry practice. Therefore, the prohibition of new single bore risers is not a new development, and even assuming there are any costs associated with that prohibition, they are properly included in the baseline because the prohibition reflects existing industry and BSEE practice.
Similarly, new paragraph (d), which was added to the final rule based on comments received, also does not impose any new costs on operators. That paragraph provides general guidance for compliance with subpart H; specifically, that in case of any conflicts between any incorporated standard and any provision in subpart H, the specific regulatory provision controls.
The only other revisions to existing § 250.800 incorporate or clarify the applicability of industry standards, previously incorporated in other sections of BSEE's regulations, to production safety equipment (
Comment—A commenter raised the concern that the initial economic analysis related to proposed § 250.801 (SPPE certification) did not discuss costs associated with BSDV certification. The commenter also asserted that the certification requirement was a BAST determination that did not comply with the BAST statute because BSEE did not demonstrate that certified valves perform better than non-certified valves.
Response—We disagree with the comment suggesting that the proposed requirement for certification of SPPE constitutes a BAST determination by the bureau and that such determination is deficient. There is no connection between the SPPE certification process and BAST determinations because, among other reasons, the certification process is not a technology; rather, certification is a verification process. In addition, BSEE has considered the costs of certification of BSDVs and other SPPE in the final economic analysis, as discussed in part V of this document.
Comment—A commenter stated that costs associated with proposed § 250.802(e) (regarding retention of certain documentation on SPPE for 1 year after decommissioning) were not discussed or analyzed in the initial economic analysis. The commenter did not, however, provide an estimate of the potential costs involved with this proposed requirement.
Response—BSEE agrees with the comment, and the SPPE document retention requirement under final § 250.802(e) is now addressed in the
Comment—A commenter asserted that potential costs under proposed § 250.806 were not included in the initial economic analysis.
Response—BSEE assumes that this comment refers to the existing § 250.806, which was reorganized and re-codified in §§ 250.801 and 250.802 of the final rule. Section 250.806 is now reserved. The provisions from § 250.806 of the existing regulations, now in final §§ 250.801 and 250.802, require certification that certain SPPE valves were manufactured under a quality assurance program standard recognized by BSEE, such as API Spec. Q1. Since those provisions were codified in the existing regulations, and rely on existing industry standards, any costs associated with those existing requirements that are retained in final §§ 250.801 and 250.802 are included in the economic baseline. The additional potential costs of complying with the new provisions of the certification requirement are included in the final economic analysis, as discussed in part V.
Comment—In connection with proposed § 250.854 (Floating production units equipped with turrets and turret-mounted systems), a commenter asserted that costs associated with new requirements were not discussed or analyzed in the economic analysis.
Response—Section 250.854 addresses floating production units with either auto slew systems or swivel stacks. Floating production, storage, and offloading facilities (FPSOs) in the GOM are already in compliance with this section, so it will not result in new costs for existing FPSOs. There are no new costs for floating production units with an auto slew system because final § 250.854 does not require the installation of new equipment. If an operator uses an auto slew system, this provision simply states that the auto slew system must be integrated with the process safety system, which does not require any new activity or equipment.
Similarly, the requirement that a floating production unit with a swivel stack must have a hydrocarbon leak detection system tied in to the process safety system imposes no new costs. These facilities already have a leak detection system, as required in their approved Deepwater Operations Plans (DWOPs), since the FPSO's swivel stack is a critical leak path subject to longstanding DWOP leak detection conditions. Further, there are no additional costs resulting from the requirement to tie the leak detection systems into the process safety system because these requirements are longstanding conditions of approval under the DWOP process for floating production units.
Comment—A commenter referenced proposed § 250.857(b) and (c) (regarding installation of certain valves on glycol dehydration units), stating that there was no clarity on whether existing glycol dehydration units must comply with this requirement, and noted that if they do need to comply, those costs must be considered. The commenter requested that the final rule address the status of existing equipment.
Response—This requirement is based on API RP 14C, which is already incorporated into BSEE regulations. The final rule simply clarifies that the location of the valves needs to be as close to the glycol contact tower as possible. As previously explained, BSEE includes the costs for following industry standards and existing regulation as part of the economic baseline.
Comment—A commenter noted that proposed new § 250.859 would require that certain firefighting systems comply with all of API RP 14G, while the corresponding provision in existing § 250.803(b)(8) only required firefighting systems to comply with section 5.2 of API RP 14G. The commenter asserted that the proposed change would have significant implications, and that the costs associated with the incorporation of the entire document were not considered in the initial economic analysis.
Response—BSEE does not agree that any costs associated with firefighting systems meeting any provisions of API RP 14G must be added to the costs of the rule. As previously stated, and as explained in the final economic analysis, any costs associated with following existing industry standards are part of the economic baseline. In addition, as previously explained, BSEE has revised final § 250.859(a) to require that firewater systems need to comply only with the relevant provisions of API RP 14G, which eliminates potential confusion as to whether firewater systems would have to meet new requirements under API RP 14G that currently do not apply to such systems.
Comment—A commenter asserted that proposed § 250.860 (regarding chemical firefighting systems) included new requirements from an existing NTL, and that BSEE should have analyzed the costs of those requirements.
Response—BSEE disagrees. As already stated, any costs associated with following the guidance provided in existing NTLs, and now contained in this final rule, are part of the economic baseline. Consistent with OMB Circular A-4, the baseline includes all practices that are already incorporated into industry and regulatory standards, and that would continue even if the new regulations were never imposed. Since NTLs interpret, and provide guidance on how to comply with, existing regulations, BSEE expects that industry already follows the NTLs to comply with the relevant existing regulations and to ensure safety and reliability of operations.
Comment—A commenter noted that proposed § 250.865(b) contained new requirements regarding pressure recording devices, and that there was no discussion in the proposed rule's preamble or the initial economic analysis concerning the need for and the costs of these new requirements.
Response—BSEE does not agree that there are new costs associated with this provision that need to be accounted for as costs in the economic analysis because the pressure recording requirements in paragraph (b) were already required by § 250.803(b)(1)(iii) of the existing regulations and, thus, are part of the economic baseline.
Comment—A commenter asserted that proposed § 250.872(a), regarding atmospheric vessels, contained new requirements and that there was no discussion in the proposed rule or the initial economic analysis concerning the need for or costs of these new requirements.
Response—BSEE disagrees. Proposed—and now final—§ 250.872(a) requires compliance with API RP 500 and API RP 505, both of which are incorporated in existing BSEE regulations (
Comment—A commenter asserted that the estimated costs ($5,000) in the initial economic analysis for proposed
Response—BSEE agrees that these costs may be higher than what was originally estimated and has adjusted the costs appropriately in the final economic analysis.
Comment—One commenter suggested that BSEE add a definition for the term “platform” to the final rule.
Response—BSEE did not propose to define that term, and has decided not to add the commenter's suggested definition to the final rule. The word “platform” can have several meanings within BSEE's regulations, depending on where and how it is used. In addition, the suggested definition was specifically related to the commenter's concerns about future development of the Arctic OCS. BSEE recognizes the importance of the concerns related to future Arctic development and recently focused on Arctic-related issues in a separate final rulemaking, as already discussed in part IV.B.3.
However, based on the comments received, BSEE has reorganized and revised the proposed changes to paragraph (c). BSEE has revised final paragraph (c)(1) to track even more closely the language of the relevant OCSLA provision. Final paragraph (c)(2) revises the proposed language to further clarify and confirm that compliance with BSEE regulations will be presumed to constitute the use of BAST, unless and until BSEE's Director determines that other technologies are required in accordance with final paragraph (c)(1). In addition, final paragraph (c)(3) revises the proposed BAST exception language to clarify that the Director may waive the requirement to use BAST for a category of existing operations if the Director determines that use of BAST for that category of operations would be impracticable. That paragraph also clarifies that the Director may waive the requirement to use BAST for an existing operation, if the operator demonstrates, and the Director determines, that using BAST in that operation would be impracticable.
Comment—Many comments asserted that the proposed changes to § 250.107 are premature and should be delayed until BSEE develops a detailed process for making and implementing BAST determinations and the National Academy of Engineering (NAE) completes a report on BAST.
Response—BSEE disagrees with these comments. BSEE did not propose any changes to or request comments on the internal processes that BSEE uses to evaluate technologies in making BAST determinations. The primary objective of the proposed changes was to better align the regulatory provisions with the statutory mandate.
That statutory provision requires:
On all new drilling and production operations and, wherever practicable, on existing operations, the use of the best available and safest technologies which the Secretary determines to be economically feasible, wherever failure of equipment would have a significant effect on safety, health, or the environment, except where the Secretary determines that the incremental benefits are clearly insufficient to justify the incremental costs of utilizing such technologies. (43 U.S.C. 1347(b).)
In OCSLA, Congress directed the Secretary to require the use of BAST in these circumstances. Over a period of years, the regulatory language used to implement this statutory provision was modified as the offshore regulations were revised. As noted in the preamble of the proposed rule, BSEE believes that the existing regulatory language does not give full effect to the BAST obligations contained in the Act. (
Revision of the BAST language in existing § 250.107 is also consistent with the recommendations of the Ocean Energy Safety Advisory Committee (OESC), which was formed following the
Thus, BSEE does not believe that the proposed regulatory changes need to be delayed until the internal BAST implementation process is fully developed. In any case, since publication of the proposed rule in 2013, BSEE has developed an internal process defining how technology will be evaluated by BSEE using a transparent and data-driven approach. This internal process was developed with significant input from many industry organizations and was discussed in detail at the BAST Conference hosted by the Ocean Energy Safety Institute on November 12, 2015. Moreover, the NAE final report on BAST, published in January 2014, was considered by BSEE in the development of this internal process. More information about the BAST Conference, NAE final report, and the BAST determination process is currently available on BSEE's BAST Web page at
Comment—Some commenters asserted that regulatory changes are unnecessary since BSEE already implements an effective BAST program through the combination of regulations, industry standards, plan and permit approvals, alternative compliance approvals, departure approvals, platform verification, inspection and enforcement, data collection, training, and the safety alert program.
Response—While BSEE agrees that it already maintains an effective BAST program, it nevertheless believes that changes to the existing regulatory language are necessary. As described in the proposed rule, and in prior responses to other comments, the changes to existing § 250.107(c) provide greater clarity and ensure consistency between the regulation and the language contained in OCSLA. BSEE agrees that, in many cases, existing regulations (including standards that are incorporated by reference in the regulations) will represent BAST. This is consistent with the intent of the language in existing § 250.107(c).
Comment—Several commenters stated that the proposed rule changes would disrupt an already established BAST process, that they would create uncertainty in the established BAST process, and that the impact of this uncertainty should be considered. Other commenters asserted that industry standards represent BAST.
Response—BSEE does not agree that the proposed or final revisions to § 250.107 would create more uncertainty. The proposed rule language essentially mirrored statutory language that has been in place since 1978 and eliminated ambiguous language that was perceived as potentially inconsistent with the statute. This final rule presents that language in an even clearer way and provides additional clarification on how BAST will be applied, while maintaining and improving alignment with the statutory language. For example, existing § 250.107 did not provide any express parameters for identifying when compliance with the regulations would no longer be considered the use of BAST. The final rule clarifies that this situation would occur when the Director makes a formal BAST determination that specific technology is required.
In addition, BSEE does not agree that consensus-based industry standards that have not been incorporated in applicable BSEE regulations automatically represent BAST. BSEE has incorporated by reference many industry standards into its regulations, and they play an important role in establishing a minimum baseline for the safety of offshore activities and equipment. And compliance with a regulation that incorporates a standard will be presumed to be the use of BAST, unless and until the Director makes a determination to require other technology(ies). However, a determination as to whether a specific, non-incorporated standard reflects BAST would need to be made by the Director on a case-by-case basis.
Comment—Several commenters asserted that the proposed rulemaking was unclear regarding what factors and thresholds BSEE will use when deciding whether it will require an operator to use a certain technology as BAST and how long the operator has to come into compliance. Other commenters asserted that existing facilities should be “grandfathered” out of any new BAST requirements.
Response—BSEE has revised § 250.107(c) of the final rule to clarify that the BSEE Director will determine when to apply a particular technology as BAST. This change is consistent with the OCSLA BAST language (and a prior delegation of the Secretary's authority to the Director). Specifically, the Director will:
• Determine when the failure of equipment would have a significant effect on safety, health, or the environment;
• Determine the economic feasibility of the technology;
• Decide whether the incremental benefits are clearly insufficient to justify the incremental costs of utilizing such technologies;
• Decide whether to waive the use of BAST for a category of existing operations because the use of BAST would not be practicable for those operations; and
• Decide whether to waive the use of BAST for an existing operation if the operator of an existing facility requests a waiver and demonstrates, and the Director determines, that the use of BAST in that existing operation would not be practicable.
BSEE does not agree, however, that an automatic “grandfathering” provision for existing facilities is appropriate. The language in OCSLA specifically makes BAST applicable to existing operations, provided that it is practicable and that the other determinations specified by the statute are made. BSEE has, however, clarified in final § 250.107(c)(3) the process for requesting a waiver from the use of BAST on existing facilities based on a demonstration by the operator, and a determination by the Director, of impracticability.
Comment—Several comments addressed the criteria and process for making BAST determinations with respect to economic feasibility, practicability, and cost-benefit analyses regarding BAST. It was suggested that BSEE define and publish its determinations for the terms “economically feasible” and “practicable,” and designate a pre-determined length of time for existing operations to come into compliance.
Commenters also suggested that BAST waivers or exceptions should be accompanied by a description of how the incremental benefits of using BAST were less than the incremental costs and should be subject to public review and comment. Commenters asserted that BSEE should incorporate the factors and thresholds on which it will determine which technology is BAST prior to finalizing the proposed rule, and that BSEE should be the ultimate decisionmaker as to BAST requirements.
Additionally, one commenter stated that the proposed text increases uncertainty in that it appears to require operators to demonstrate that the incremental benefits of using BAST are insufficient to justify the costs in order to obtain an exception, which improperly shifts the burden to the operator.
Response—BSEE agrees that some clarifications and revisions of the benefit-cost determination and the proposed exception language are appropriate. Consistent with Congress' intent concerning the evaluation of costs and benefits, final paragraph (c)(1) now clarifies that the Director will determine
BSEE does not agree, however, with the comments suggesting that the final rule include definitions or specific factors or “thresholds” for economic feasibility and practicability on which the Director will make BAST determinations or waiver decisions, respectively. OCSLA requires that BSEE (through a delegation from the Secretary) make BAST determinations, and BSEE has developed its formal process for BAST determinations in line with that authority. Every BAST determination requires a benefit-cost analysis of its own, to demonstrate that the BAST candidate technology is economically feasible and that it will result in benefits that are not clearly insufficient to justify the costs. For any future BAST determinations, BSEE will specify what is economically feasible for BAST purposes through rulemaking, except in cases involving emergency safety issues. These decisions will be largely technology- and fact-specific, and it would be premature to specify in this rule how such facts will be considered in particular cases.
In any case, the proposed and final revisions of the language in § 250.107(c) do not constitute a BAST determination and do not address BSEE's internal processes for making specific BAST determinations. BSEE revised this section in the final rule in large part to clarify that the BSEE Director will determine when to make those specific BAST determinations in accordance with the statutory criteria.
Similarly, “practicability” demonstrations and decisions for waiver requests will depend on the circumstances of the existing operations at issue. However, BSEE expects that unique factors, such as the types or ages of specific facilities or environmental conditions, that make installation of BAST impracticable will be relevant in this decisonmaking.
Comment—One comment requested that BSEE place a time limit on itself to review requests under the proposed provision allowing an operator to request an exception from using BAST by demonstrating that the incremental benefits are clearly insufficient to justify the incremental costs. The commenter said that BSEE's estimate that it would take an operator 5 hours to prepare the information to satisfy the proposed requirements for an exception is inadequate. The commenter asserted that it would take many more hours to compile, analyze and prepare information that demonstrates to BSEE that the operator's technology fits the exception to BAST. The commenter also asserted that BSEE will require far more time than predicted to analyze and review the information required by the proposed exception provision. Furthermore, the commenter stated that BSEE has not provided any guidance or process for implementing this proposed requirement.
Response—BSEE does not agree with the suggestion that it needs to establish a more-detailed BAST exception (waiver) process or provide guidance for waivers prior to revising § 250.107(c). BSEE may, however, provide guidance on the implementation of the BAST requirements, including the waiver process, in the future.
The commenter's concern that a request for an exception under the proposed language would likely take many hours to complete and review has been effectively resolved by the revisions in final § 250.107(c)(3), which now provides that the operator only needs to demonstrate that use of BAST is not practicable (
Comment—One commenter requested clarification as to the definition of “failure” in the context of the proposed § 250.107(c)(1), which stated that “[w]herever failure of equipment may have a significant effect on safety, health, or the environment . . . .” the use of BAST is required. The commenter stated that “failure” could have multiple meanings including mechanical failure, electrical failure, or test failure.
Response—BSEE does not agree that a specific definition of “failure” is necessary. The relevant language is drawn directly from OCSLA, which states that BAST must be used “[w]herever failure of equipment would have a significant effect on safety, health, or the environment . . .” BSEE used this language in the proposed and final rule to provide parameters for the types of failure that trigger the OCSLA requirement to use BAST. The Director would not require the use of BAST equipment if failures of that equipment would not result in a significant effect on safety, health, or the environment. What constitutes failure of equipment depends upon the context of the operation and equipment. Under this section, BSEE is addressing equipment failure as a general matter. Specific provisions related to equipment functionality are addressed in existing regulatory provisions and throughout this final rule.
Comment—One commenter requested clarification on proposed § 250.107(c)(1)(ii), which proposed that operators must use economically feasible BAST, “wherever practicable on existing operations.” The commenter requested clarification as to whether, at the discretion of BSEE personnel, existing equipment that is properly operating under normal conditions would need to be replaced even if it did not pose a threat of a malfunction or failure.
Response—In the final rule, BSEE revised the language of proposed § 250.107(c) to clarify that the Director will make the BAST determinations regarding economic feasibility and other
In addition, the Director may waive the requirement to use BAST for an existing operation if the operator of an existing facility submits a waiver request demonstrating, and the Director then determines, “that the use of BAST would not be practicable” in that operation. For example, if an operator demonstrates, and the Director determines, that such technology(ies) would be unduly difficult or impossible to retrofit at an existing facility, the Director could grant the operator a waiver. In the absence of a waiver, however, existing operations must comply with BAST. As explained in response to other comments, OCSLA expressly requires the use of BAST for existing operations, whenever practicable, so Congress did not view existing technologies inherently to represent BAST.
Comment—Several commenters asserted that BSEE had not met its obligations under the RFA with regard to the proposed BAST language;
Response—BSEE does not agree that it failed to comply with the RFA regarding the cost impact on small entities of the proposed revisions to § 250.107(c). As previously explained in part IV.C.2, the proposed and now-final revisions to the BAST language impose no significant new costs on any entity, small or otherwise. The final revisions to § 250.107(c) clarify the intent of the existing regulation and better align the regulatory language with the longstanding BAST language in OCSLA. In addition, the commenters' claim regarding the costs of the proposed deletion of former language equating compliance with BSEE regulations with BAST is moot, since the final rule now includes language maintaining that longstanding regulatory principle.
As stated in previous responses, since the revisions to § 250.107(c) do not establish a new BAST program or new BAST requirements, but rather clarify and incorporate existing baseline statutory and regulatory principles governing BAST compliance, they create no new costs for small entities.
Comment—Commenters asserted that this rule constitutes a “significant regulatory action” which should trigger a review by the Office of Information and Regulatory Affairs (OIRA) of its anticipated costs and benefits. The commenters noted that the proposed rule and its supporting documentation indicated that both BSEE and OIRA determined that this rule is not a significant rulemaking under E.O. 12866. Commenters asserted that both the proposed rule and the initial economic analysis considered only the potential costs and benefits of the proposed regulatory provisions of subpart H. Commenters suggested that this analysis—and by extension, the resulting determination that the proposed rule would not be significant—omits any consideration of estimated impacts from BSEE's proposed revision to the BAST rule in subpart A. Commenters also asserted that BSEE omitted the costs arising from the significant uncertainty the proposed BAST rule interjects into the operations and decision making by regulated entities that have long depended upon BSEE's regulations and regulatory process for implementing BAST in their offshore planning.
Response—BSEE does not agree that its and OIRA's determination that this is not a significant rulemaking under E.O. 12866 is incorrect, especially with regard to the revised BAST language. As previously explained in responses to other comments, the revisions to § 250.107(c) do not create a new BAST program or reflect any new BAST determinations, but rather merely clarify and incorporate longstanding baseline statutory and regulatory principles regarding BAST compliance, and, thus, impose no new costs on operators. The concerns related to the loss of certainty provided by regulatory compliance presumptively constituting BAST are likewise mitigated by the revisions BSEE made from the proposed to the final rule.
Comment—One commenter suggested that BSEE has acknowledged that technologies already in place are BAST. The commenter also proposed language that recognizes that existing technologies meet the intent of OCSLA.
Response—BSEE does not agree that the commenter's suggested language change is necessary or appropriate. The proposed concept is not consistent with OCSLA or its implementing regulations. Existing BSEE regulations at § 250.105 define BAST as “the best available and safest technologies that the BSEE Director determines to be economically feasible wherever failure of equipment would have a significant effect on safety, health, or the environment.” This existing definition is consistent with the language and intent of OCSLA and clarifies that the Director may make BAST determinations on an industry-wide basis or for different classes or categories of operations based on economic feasibility. BSEE revised the BAST provisions under § 250.107(c) in the final rule to be consistent with OCSLA and, thus, with the existing definition. The revisions also clarify that the Director will determine when to deem specific technology—not already required by BSEE's regulations—to be BAST, using the criteria specified in OCSLA, and that the Director also will determine when to waive the application of BAST to existing operations. Moreover, since OCSLA expressly requires the use of BAST, as determined in accordance with OCSLA, for existing operations whenever
Comment—One commenter observed that some of the standards incorporated by reference into the proposed rule are already incorporated into other parts of the existing regulations.
Response—Standards may be incorporated into multiple parts of the regulations, as when similar equipment may be used for different operations subject to different regulatory provisions. For example, subparts H and I require similar considerations for design; incorporating the same standards in relevant sections of both subparts ensures that the production safety system and the platform or structure are integrated. In other cases, BSEE has decided that the same standards should apply for other reasons. For example, pipelines, which are regulated under subpart J, and certain aspects of production safety systems related to piping, regulated under subpart H, implicate several of the same standards and BSEE has determined that it is important to incorporate each relevant standard in all regulatory sections to which it applies.
Comment—One commenter requested an explanation of how BSEE determined that each standard proposed for incorporation in the regulations was the best available and safest technology and operating practice for the OCS.
Response—The incorporation of industry standards does not reflect a specific BAST determination by BSEE. The authority to incorporate industry standards into BSEE regulations is separate from the BAST authority. The National Technology Transfer and Advancement Act (NTTAA) mandates that Federal agencies use technical standards developed or adopted by voluntary consensus standards bodies, as opposed to using government-unique standards, where practicable and consistent with applicable law. These criteria for rulemaking are different from those applicable to BAST determinations under OCSLA and § 250.107(c). BSEE follows the requirements of the NTTAA and the relevant guidance in OMB Circular A-119 when incorporating standards into its regulations.
Comment—Some commenters expressed concern about the availability of the standards incorporated by reference in the proposed rule. They were concerned that many standards are not easily accessible or generally available to the public as part of the rulemaking process or thereafter. One commenter estimates that the public's burden for purchasing the industry standards that were not made available to the public would be approximately $5,900. This amount includes all the standards referenced at § 250.198 that are not available to the public free-of-charge. Some commenters also stated that the public cost burden makes meaningful public participation in rulemaking cost-prohibitive and proposes that BSEE change its process for incorporating standards.
Response—As discussed in part II.C of this document, all standards incorporated by reference in BSEE's regulations are available to view for free
The estimate provided by the commenter ($5,900 to purchase the standards that were not made available to the public for this rulemaking) includes standards already incorporated into existing BSEE regulations. The commenter stated that the $5,900 estimate includes all the standards referenced in § 250.198 that are not available to the public free-of-charge. The estimated cost, therefore, includes standards that are not incorporated into subpart H or related to this rulemaking and overstates the costs associated with this rulemaking.
Comment—Commenters expressed concern that there is a lack of clarity regarding precedence when a standard conflicts with a regulation. Commenters stated that the regulations should specifically state that wherever BSEE's regulations are more specific or provide more stringent requirements than those listed in an industry standard, BSEE's regulations take precedence.
Response—BSEE has provided clarification, in final § 250.800(d), that if there is a conflict between the standards incorporated through this rulemaking and other provisions of subpart H, the operator must follow the regulations.
Comment—Commenters asserted that: BSEE should go through the process of public review and comment prior to incorporating a new or updated standard: There should be at least a 30-day public review and comment period on proposed rulemakings to update an industry standard; and BSEE should provide a technical support document for that proposed rulemaking showing how BSEE determined the updated standard to be the best available and safest technology and operating practices and explaining why incorporating the industry standard results in a safety improvement.
Response—The commenters' requests as to how BSEE should incorporate industry standards in the future is beyond the scope of this rulemaking. As previously discussed, in this rulemaking BSEE made all of the documents incorporated by reference available for public review in connection with the comment period provided for the proposed rule and continues to make publicly available at its office all of the standards incorporated by reference in the final rule.
In any event, in its rulemakings, BSEE complies with the NTTAA requirement that an agency “use standards developed or adopted by voluntary consensus standards bodies rather than government-unique standards, except where inconsistent with applicable law or otherwise impractical.” (OMB Circular A-119 at p. 13). BSEE also complies with the OFR regulations governing incorporation by reference. (
Finally, as previously explained, the incorporation of industry standards does not reflect a specific BAST determination by BSEE; those actions derive from separate authorities and are governed by different criteria.
Comment—Commenters suggested that BSEE should: Review all industry standards listed in § 250.198 to eliminate discontinued standards; update standards for which newer versions have been published, if BSEE determines the updated standard version provides BAST and operating practice improvements; and eliminate standards that no longer represent BAST and best operating practices.
Response—This comment, seeking future action by BSEE to amend § 250.198, is also outside the scope of this rulemaking. BSEE reiterates that a decision to incorporate, or revise an existing incorporation of a standard is separate from specific BAST determinations. Nonetheless, BSEE engages in retrospective review of its regulations in accordance with E.O. 13563 and E.O. 13610 “to ensure, among other things, that regulations incorporating standards by reference are updated on a timely basis . . . .” (OMB Circular A-119 at p. 4). In fact, BSEE has already begun reviewing many of the standards incorporated in the existing regulations and will provide additional information regarding its review when appropriate. If BSEE decides that some updating of incorporated standards (
Comment—A commenter pointed out that the proposed revision actually belongs in existing § 250.518.
Response—BSEE agrees and has corrected the section number in the final rule to § 250.518 (Tubing and wellhead equipment).
Comment—A commenter pointed out that the proposed revisions actually belong in § 250.619, not § 250.618.
Response—BSEE agrees and has corrected the section number to “§ 250.619” in the final rule.
Final paragraph (c), as proposed, also provides examples of FPSs (
BSEE also added the parenthetical “(
Based on public comments, BSEE also added a new paragraph (d) to clarify that if there are differences between the incorporated industry standards and the regulations, the operator must follow the regulations. Finally, BSEE added new paragraphs (e) and (f) to point out that operators may submit requests to use alternate procedures or equipment or for a departure from the subpart H regulations under existing §§ 250.141 and 250.142, respectively.
Comment—Some commenters took issue with the requirement for dual barrier production risers, stating that the term “production riser” may have several meanings. Commenters asserted that dual barrier production risers do not need to be used when subsea trees are in place, but accepted that dual barrier production risers are appropriate when using dry trees. Commenters also stated that using single barrier production risers downstream from subsea trees is a widely-accepted industry practice and that “it has generally been considered safe practice to complete wells through [an] outer riser, using mud weight and the outer riser to provide two barriers with a surface blow out preventer having at least two rams.” Commenters asserted that requiring dual barrier risers downstream from subsea trees would be uneconomical or impossible. Commenters stated that where subsea trees are used, the tree provides a failsafe barrier to the ocean and, thus, that using single barrier risers downstream of subsea trees is a safe and acceptable practice. Commenters asserted that “a blanket ban on one particular type of riser configuration and operation does not comply with the statutory requirement for BAST or with the industry experience” and urged BSEE to reconsider the proposed rule.
Response—Final § 250.800(c)(2) only applies to the installation of production risers from new FPSs.
Comment—Several commenters expressed concern about how the prohibition on installation of single bore production risers will affect existing single bore production risers. Commenters asserted that this technology is acceptable in some applications, and that BSEE should allow future uses of single bore production risers in certain circumstances given that such risers may allow for production from reservoirs that would otherwise be uneconomical. Commenters stated that the preamble of the proposed rule did not provide any detail on why BSEE believes this situation to be unacceptable and asked that BSEE provide justification for prohibiting a technology that has not been proven to be problematic. Furthermore, the commenters asked why, if BSEE believes this practice to be unsafe, BSEE would allow this practice to be available for up to a year after the publication of the final rule.
Commenters also recommended revising the regulatory text to confirm that operators can seek relief from the requirements of subpart H where appropriate.
Response—This section of the proposed and final rule does not address drilling, flowline, or pipeline risers; it only addresses single bore production risers installed on FPSs after the effective date of the rule. Moreover, the concerns about the prohibition on installation of single bore risers is academic, since it has been more than 8 years since BSEE approved the installation of any new single bore production risers; thus, in effect, the regulatory prohibition reflects longstanding BSEE policy and industry practice.
As to currently installed single bore risers, neither the proposed nor the final rule prohibits their continued use. Operators may continue to use single bore production risers that are currently installed, although when work is performed through a single bore production riser, it causes wear on the riser, compromising its integrity. Thus, additional precautions for wear protection, wear measurement, fatigue analysis, and pressure testing prior to performing any well work with the tree removed are necessary for currently installed single bore risers. This is consistent with established BSEE policy and past approvals for well operations using currently installed single bore production risers. It is possible to do this work safely if the existing riser is in good shape, but there is no room for error or failures, since a single bore riser has only a single mechanical barrier and the consequences of failure of a single bore riser with open perforations could be serious; that is why BSEE has long required in permitting decisions, and is now codifying the requirement, that operators use dual barrier production risers for new installations.
Regarding the implementation date for the prohibition of single bore risers, BSEE agrees with the commenter that making the prohibition effective in 1 year was not appropriate under the circumstances; thus, BSEE has changed the effective date of this provision in the final rule to be the same as the effective date of the rule. If there is a question about what a single bore production riser is and how this provision applies to a specific situation, the operator may contact the appropriate District Manager.
Further, as suggested by some commenters, BSEE has added new paragraphs (e) and (f) to the final rule to point out that operators may seek approval to use alternate equipment or procedures in lieu of, or request departures from, the requirements of subpart H in accordance with existing §§ 250.141 and 250.142, respectively. Several provisions of the proposed rule included similar language; however, since the alternate compliance and departure provisions apply to all sections of part 250, it is not necessary to cite them expressly throughout the final rule. By including a single reference to §§ 250.141 and 250.142 in final § 250.800, BSEE confirms that those provisions are applicable to all subpart H requirements.
Comment—Commenters raised an issue related to proposed paragraph (c), requiring that all new FPSs comply with API RP 14J. Commenters stated that API RP 14J is a guidance document that identifies multiple tools for conducting a hazards analysis on offshore facilities, but noted that the proposed rule did not specify which tool(s) the operator must use to meet BSEE's expectations. Commenters also asserted that operators are already required to conduct a hazards analysis using one of the tools identified in API RP 14J or another recognized document in accordance with subpart S of BSEE's regulations, (
Response—BSEE disagrees with the suggested changes to this section. API RP 14J, incorporated in final § 250.800(c) (for FPSs), was already incorporated by reference in former § 250.800(b) for the same types of facilities. Therefore, operators should already be complying with the relevant requirements, and this comment actually suggests eliminating existing regulatory requirements rather than modifying the proposed requirements. The existing and proposed (and now final) requirements are consistent with and complementary to those in the existing subpart S regulations. The operator may use any hazards analysis that satisfies subpart H to meet the requirements under existing § 250.1911 of subpart S; however, final § 250.800(c) will ensure that operators use an appropriate hazards analysis method selected in accordance with the relevant hazards analysis provisions of API RP 14J.
This section of the final rule also specifies that BSEE will not allow subsurface-controlled SSSVs on subsea wells and omits the reference to the ANSI/ASME standards found in existing § 250.806 because those standards are outmoded or have been withdrawn. The final rule also provides that SPPE equipment that is manufactured and marked pursuant to API Spec. Q1 will be considered certified SPPE under part 250. Although SPPE that is not manufactured or stamped pursuant to API Spec. Q1 is presumptively non-certified, final § 250.801(c) provides that BSEE may exercise its discretion to accept SPPE manufactured under quality assurance programs other than API Spec. Q1, provided that an operator submits a request to BSEE containing relevant information about the alternative program, that an appropriately qualified third-party verifies the alternative program as equivalent to API Spec. Q1, and that BSEE approves the request. In addition, final paragraph (c) authorizes an operator to request that BSEE accept SPPE that is marked with a third-party certification mark (other than an API monogram).
Comment—Commenters expressed concern that proposed § 250.801 would only recognize the quality assurance program in API Spec. Q1 for certified SPPE. Those commenters suggested broadening the coverage of the rule to include International Organization for Standardization (ISO) 9001, “Quality Management Standards—Requirements”) (2015). Another commenter recommended that the equipment be marked by the manufacturer with the API Monogram as proof of conformance with the proposed requirement.
Response—BSEE evaluated this recommendation and has determined that the proposed quality assurance program requirements under paragraphs (a) and (b) are appropriate and provide sufficient flexibility. Nonetheless, BSEE has revised final § 250.801(c) to clarify that an operator may submit a request to BSEE to accept SPPE manufactured under another quality assurance program as compliant with paragraph (a), provided that an appropriately qualified entity (such as one that meets the criteria of ISO 17021-3, “Conformity assessment—Requirements for bodies providing audit and certification of management systems—Part 3: Competence requirements for auditing and certification of quality management systems,” or similar criteria) verifies that the other quality assurance program is equivalent to API Spec. Q1. In addition, although BSEE has decided that a monogram requirement is not necessary, since this provision helps ensure the quality of the SPPE during the manufacturing process, BSEE will consider the marking of SPPE with the API monogram or a similar third-party certification mark, as alternative evidence of conformance with this section.
Comment—One commenter requested clarification of the definition of a BSDV. Another commenter requested that BSEE clarify that only those valves associated with subsea systems qualify as BSDVs.
Response—According to the Barrier Concept (as discussed in BSEE NTL No. 2009-G36), for subsea wells, the BSDV is the surface equivalent of an SSV on a surface well. BSEE has added text to § 250.801(a)(2) in the final rule to clarify this point. Thus, the function of the BSDV is similar to the function of the SSV, and since the BSDV is a critical component of the subsea system, it is appropriate for BSDVs to be subject to the same requirements as SSVs under § 250.801. This also ensures the appropriate level of safety for the production facility. Final § 250.835 states that BSDVs are associated with subsea systems; this point is also emphasized by the revised text in final § 250.801(a)(2).
Comment—Commenters requested clarification as to whether BSEE will deem existing SPPE acceptable, despite new certification requirements, until such equipment can be replaced. A commenter also requested clarification of the estimated impact on the cost and supply of SPPE equipment once ANSI/ASME SPPE-1-1994, “Quality Assurance and Certification of Safety and Pollution Prevention Equipment Used in Offshore Oil and Gas Operations,” is no longer acceptable as an SPPE certification program.
Response—Section 250.806 of the existing regulations contained requirements similar to those in proposed § 250.802(d) regarding the use and installation of certified SPPE. Specifically, existing § 250.806 required use of certified SPPE if that SPPE was installed on or after April 1, 1998. However, existing § 250.806 also provided that non-certified SPPE in use as of that date could continue in service unless and until that equipment needed offsite repair, remanufacture or hot work (such as welding). Similarly, final § 250.802(d), as proposed, confirms that operators may continue to use any existing non-certified SPPE already in service unless and until it needs offsite repair, remanufacture or hot work. In addition, since final § 250.801 includes BSDVs as SPPEs (beginning September 7, 2017), the final rule provides that operators have until that date to come into compliance with the certification requirements for any new BSDVs; moreover, under final § 250.802(d), currently installed non-certified BSDVs may remain in service unless and until they require offsite repair, remanufacture or hot work.
The commenter's question about the cost and supply impacts that could occur once ANSI/ASME SPPE-1 was no longer recognized is already moot. That standard was withdrawn by industry in favor of API Spec. Q1 in 2013. Thus, the final rule should not adversely affect SPPE costs or supplies because industry has already evolved in keeping with the change in industry standards from ANSI/ASME SPPE-1 to API Spec. Q1.
Comment—One commenter asserted that a report referred to in the proposed rule
Response—BSEE disagrees with the suggestion that certification provides no additional assurance that critical safety equipment will perform as designed. The referenced report was not the only factor considered when developing the proposed SPPE certification requirements. The existing regulations have required use of certified SPPE since April 1, 1998. In developing the new proposed and final certification requirements, BSEE considered the effectiveness of this longstanding requirement, as well as the existence of industry standards (such as ANSI/ASME SSPE-1 and API Spec. Q1) that support the requirement for certification to ensure the quality and effectiveness of this equipment. The only substantive addition to the final rule regarding SPPE certification requirements is that BSDVs will be considered SPPE that must be certified and otherwise conform to final § 250.801. As stated elsewhere, BSEE considers the BSDV on subsea wells to be the equivalent of an SSV on a surface well and it is appropriate to include BSDVs as SPPE under § 250.801.
Moreover, under § 250.804(a)(5) of the existing regulations, USVs were required to meet a zero leakage requirement and to be replaced or repaired if they failed to do so. However, since BSDVs will need to be certified (when required) under final §§ 250.801(a)(2) and 250.802(d), and to meet the zero leakage requirement under final § 250.880(c)(4)(iii), USVs used in connection with BSDVs will no longer be required to do so.
In any event, operators may continue to use existing non-certified SPPE already in service until it requires offsite repair, re-manufacturing, or hot work, at which time the operator must replace the non-certified SPPE with SPPE that conforms to the requirements of final § 250.801.
Regarding the comment on certain standards that were not referenced in the proposed rule, BSEE continually works to review various standards for possible incorporation, including those from API, ANSI, and other standards development organizations. The standards referred to in this comment may be considered in future rulemakings. However, the fact that BSEE does not incorporate by reference a particular standard does not preclude an operator from voluntarily complying with that standard. BSEE presumes that industry follows its own standards, regardless of whether BSEE incorporates them in the regulations.
Comment—A commenter suggested that the proposed SPPE certification requirements be expanded to include all SPPE used for any production systems on the OCS where flammable petroleum gas or volatile liquids are produced, processed, compressed, stored, or transferred, and not be limited to the four types of valves listed in § 250.801(a).
Response—BSEE does not agree that the suggested expansion of the certification requirement is appropriate at this time. The particular SPPE identified in this section is specifically used for controlling the flow of fluids from the wellbore. The other equipment mentioned by the commenter is for processing the fluids, and that equipment has separate design, installation, and maintenance requirements under other subparts of part 250 (
Comment—A commenter requested further information regarding the expected duration of BSEE review for SPPE equipment approval based on alternate quality assurance programs; the process by which BSEE will approve SPPE; and whether recertification will be required on a periodic basis.
Response—The time required for BSEE to evaluate SPPE manufactured under other quality assurance programs depends on the type and quality of the information submitted. Under final § 250.801(c), only SPPE manufactured under quality assurance programs other than ANSI/API Spec. Q1 would require approval from BSEE. BSEE will handle each evaluation on a case-by-case basis, but because this is expected to happen infrequently, this process will not create serious delays in approval of such equipment. Recertification of SPPE is not required; however, final § 250.802(b) incorporates standards that require for regular testing of SPPE, and final § 250.802(d) contains provisions addressing when the operator must replace existing equipment with certified SPPE.
Final § 250.802(c) includes a summary of some of the requirements contained in the documents that are incorporated by reference in order to provide examples of those types of requirements. These requirements cover a range of activities affecting the SPPE over the entire lifecycle of the equipment and are intended to increase the reliability of the equipment through a lifecycle approach.
Final § 250.802(c)(1) also requires that each device be designed to function and to close in the most extreme conditions to which it may be exposed; this includes extreme temperature, pressure, flow rates, and environmental conditions. Under the final rule, the operator must have a qualified independent third-party review and certify that each device will function as designed under the conditions to which it may be exposed. Final § 250.802(c) also describes particular SPPE specifications and testing requirements.
BSEE has included a table in final § 250.802(d) to clarify when operators must install SPPE equipment that conforms to the requirements of § 250.801. Under the final rule, non-certified SPPE already in service can remain in service until the equipment requires offsite repair, re-manufacturing, or any hot work, in which case it must be replaced with SPPE that conforms to the requirements of § 250.801.
Final § 250.802(e) requires operators to retain all documentation related to the manufacture, installation, testing, repair, redress, and performance of SPPE until 1 year after the date of decommissioning of the equipment.
Comment—Commenters requested clarification of the meaning of “lifecycle approach.”
Response—Although this term is not used in the regulatory text, the lifecycle approach involves vigilance throughout the entire lifespan of the SPPE, including design, manufacture, operational use, maintenance, and eventual decommissioning of the equipment. This approach considers “cradle-to-grave” issues for SPPE and is a tool to evaluate the operational use, maintenance, and repair of SPPE over its lifetime. Addressing the full lifecycle of critical equipment is essential to increasing the overall level of confidence that this equipment will perform as intended in emergency situations. As discussed earlier in part II.B, this concept is currently reflected in several industry standards for SPPE (
A major component of the lifecycle approach involves the proper documentation of the entire process, from manufacture through the end of the operational limits of the SPPE, which allows for continual improvement throughout the life of the equipment by evaluating mechanical integrity and improving communication between equipment operators and manufacturers.
Comment—A commenter stated that it is dangerous to open a large diameter valve with full differential pressure across the valve's gate and, thus, revisions should be made to the proposed language to allow an arrangement where a smaller valve, at full differential pressure, first opens to reduce the pressure across the larger valve.
Response—BSEE does not agree that the suggested revision is necessary. BSEE does not expect the operator to open a large diameter valve with full differential pressure across the gate. Nothing in this section prohibits use of smaller diameter actuated valves in equalization lines, assuming that the smaller actuated valves can be isolated with a manual valve. This section provides the basic requirements for the functioning of the device, meaning that it has to close under the most extreme conditions to which it may be exposed, but does not specify precisely how that must be done.
Comment—A commenter requested clarification on the meaning of the “traceability” requirement in proposed paragraph (c)(5).
Response—Section 250.802(c)(5) requires operators to comply with and document all manufacturing, traceability, quality control, and inspection requirements for SPPE subject to subpart H, including the standards incorporated by reference in the regulations. Traceability refers to the ability to document the installation, maintenance, inspection and other significant events during the “lifecycle” of the particular piece of equipment as they relate to the equipment's proper functioning. This includes, for example, documenting the marking of the equipment received from the manufacturer, so the operator can accurately track each piece of SPPE during its useful life. The standards incorporated by reference in final § 250.802(a) and (b) contain specific provisions on traceability.
Comment—A commenter suggested that independent third-parties may not have the expertise required to conduct the lifecycle analysis on SPPE that was called for in § 250.802(c)(1) of the proposed rule. That commenter also suggested that limiting third-party certifiers to API-approved independent third parties would limit the pool of expertise, which would delay certification. Another commenter requested clarification as to the criteria for establishing whether a third-party reviewer has sufficient expertise and experience to perform the review and certification. That commenter also asked whether third-party reviewers will require periodic reevaluation.
Response—Final § 250.802(c)(1), as proposed, requires the independent third-party to have sufficient expertise and experience to perform the SPPE review and certification. Contrary to one commenter's assumption, however, § 250.802(c)(1) does not limit the pool to API-approved independent third parties.
Finally, § 250.802(c)(1) does not require periodic revaluation of third-party reviewers; however, the operator will be responsible for ensuring that any third-party it employs possesses “sufficient expertise and experience” under § 250.802(c)(1) whenever the third-party performs the reviews and certifications required by this section.
Comment—A commenter asserted that it is unclear from the proposed language how BSEE would verify lifecycle analysis without imposing an unwieldy document review process. The commenter suggested that third-party certification is one way to conduct such verification and to ensure compliance with the rule without BSEE reviewing all of the documentation.
Response—BSEE disagrees with the commenter's premise. Section 250.802 of the final rule does not require that documents related to the lifecycle approach be submitted to or reviewed by BSEE. Paragraph (e) of that section requires only that all documents related to the manufacture, installation, testing, repair, redress, and performance of SPPE be retained until one year after the equipment is decommissioned. If BSEE identifies a need to review any specific documentation to verify that the lifecycle approach is being followed in a particular case, it can request that documentation.
Comment—A commenter noted that the proposed rule would allow non-certified SPPE to remain in service. The commenter suggested that non-certified SPPE should be replaced over a specified period of time and eventually
Response—BSEE does not believe that the commenter's suggested requirement is necessary. The regulation (existing § 250.806(b)(2)) that is being revised and replaced by final § 250.802(d) already required, as of April 1, 1998, that operators replace non-certified SPPE that needed offsite repair, re-manufacturing, or any hot work with certified SPPE. Thus, most existing SPPE is already certified under the existing regulation; this final rule essentially adds BSDVs and their actuators to that certification requirement (beginning September 7, 2017). Moreover, final § 250.802(d) also requires any remaining non-certified SPPE that needs offsite repair, remanufacturing or hot work to be replaced with certified SPPE. In addition, all SPPE must meet specific testing requirements pursuant to final § 250.880. Any existing, non-certified SPPE that fails such tests and that is in need of offsite repairs, remanufacturing, or hot work, must be replaced with certified SPPE pursuant to final § 250.802(d). Existing § 250.806(b)(2) also permitted installation, prior to April 1, 1998, and use of non-certified SPPE only if it was in the operator's inventory as of April 1, 1988, and was included in a list of noncertified SPPE submitted to BSEE prior to August 29, 1988. Thus, BSEE expects that non-certified SPPE will be replaced by certified SPPE over time without the need for the additional requirements suggested by the commenter.
Comment—A commenter suggested that the proposed language of § 250.802(a) and (c) was inaccurate, internally inconsistent, and not in agreement with the overall intent of the proposed rule. Specifically, the commenter stated that, although BSDVs are included in paragraph (a), BSDVs are not specifically addressed in the referenced standards, and the rule should instead include a reference to API RP 14H for BSDVs. The commenter also asserted that the intent of the independent third-party language in proposed paragraph (c)(1) was to require no more than a simple certification and marking with the API monogram by the manufacturer, and that requiring an independent third-party to certify functionality of every individual item of equipment would not be achievable.
Response—BSEE does not agree with the commenter's implied assertion that the inclusion of BSDVs in paragraph (a) is inconsistent with the language of that paragraph incorporating API Spec. 6AV1 and API/ANSI Spec. 6A. Although those standards do not expressly refer to BSDVs, their specifications apply to surface valves, which is a term broad enough to encompass BSDVs. In any event, if there is any conflict between any document incorporated by reference and the regulations, the regulations control; thus, the asserted intent of the developer of the standard does not constrain the terms of BSEE's regulations.
Nor does BSEE agree that this section should reference API RP 14H for BSDVs, given that final § 250.836 requires all new BSDVs and BSDVs that are removed from service for remanufacturing or repair to be installed, inspected, maintained, repaired, and tested in accordance with API RP 14H's requirements for SSVs. That standard is also referenced in § 250.880(c)(4)(iii), which requires operators to test BSDVs according to API RP 14H's requirements for SSVs.
BSEE also does not agree with the commenter's concerns regarding the independent third-party requirement in final § 250.802(c)(1). The independent third-party does not guarantee permanent functionality of the SPPE, as implied by the commenter, but certifies that—at the time of certification—the equipment will function as designed under the conditions to which it may be exposed.
Comment—Several commenters requested clarification on the requirement for independent third-party review and certification of SPPE equipment design under proposed § 250.802(c)(1). Specifically, commenters asked whether BSEE will require approval of the use of a particular certified verification agent (CVA), and whether BSEE will accept wholesale certification by a single supplier of all equipment provided by that supplier.
One commenter also requested clarification as to whether requalification testing performed following equipment design changes will be required, and whether requalification testing will apply only to the manufacturer that makes the design changes.
One commenter recommended that, if BSEE keeps the certification requirement in the final rule, then BSEE should extend the 1-year timeframe in § 250.801(a)(2) before BSDVs are considered to be SPPE to 2 years, thereby extending the compliance date for use of certified BSDVs to 2 years after publication of the final rule. Commenters also expressed concern about the costs of replacing, repairing, or remanufacturing existing (non-certified) SPPE and maintaining documentation for SPPE equipment. In particular, commenters asserted that, where no isolation valve exists, installation or replacement of a safety valve would require excessive shutdown time and construction work on lines that have previously contained hydrocarbons. They also suggested that this result would greatly increase the risk of a serious incident from arbitrarily replacing a non-certified valve that cannot be shown to be inferior to a certified valve.
Response—With regard to the comment on CVAs, BSEE does not intend at this time to limit the pool of independent third-party reviewers by approving or requiring particular certification agents. As stated in an earlier response, if warranted, BSEE can review the qualifications of any independent third-party reviewer and may provide additional guidance in the future, if appropriate, regarding third-party certifiers' experience, expertise and independence.
With regard to requalification testing of SPPE, proposed and final § 250.802(c)(4) expressly state that, if there are manufacturer design changes to a specific piece of equipment, requalification testing is required. With regard to whether the proposed requalification testing requirement applies only to the manufacturer that makes a design change, the answer is “no.” When read in conjunction with final § 250.802(c)(3), paragraph (c)(4) requires that requalification testing be performed by an API-licensed test agency. Final paragraph (c)(4) specifies, as proposed, that the operator (
BSEE disagrees with the request to extend the timeframe for BSDVs to meet the SPPE requirements, including the certification requirement. The 1-year timeframe for BSDVs to be considered SPPE is sufficient, especially since paragraph (d)(3) of this section provides that non-certified SPPE (which will include BSDVs 1 year after publication of the final rule) that is already in service need not be replaced with certified SPPE until it requires offsite repair, re-manufacturing, or any hot work.
Comment—A commenter requested clarification as to the meaning of “most extreme conditions” to which each SPPE device may be exposed and who has the authority to define the term. The
Response—The operator is responsible for determination and application of the specific wellbore conditions. As with other aspects of operations, the operator is responsible for making reasonable assumptions and must document and explain those assumptions through the application process. An operator is not responsible for ensuring that SPPE is designed to function at conditions that are not reasonably anticipated during production operations. Conversely, an operator is responsible for ensuring that its proposed SPPE is designed to function properly in the conditions that a qualified and prudent OCS operator should reasonably expect to encounter during the production operation.
For the independent third-party, BSEE will not approve or select appropriate parties. However, BSEE may review the qualifications and expertise of an independent third-party if there is an issue concerning an independent third-party's certifications. Operators must have SPPE certified on a per well basis, because each well will have different operating and environmental conditions.
Comment—BSEE received multiple comments on the costs associated with industry standards incorporated by reference, and notations that the economic analysis fails to identify those costs. These comments included questions on the economic analysis baseline; whether the economic analysis accurately portrays the 1988 final rule and agency regulations; discussion of the costs of new requirements in API 570 for piping system inspection; and the allegation that the agency did not include or analyze the costs associated with proposed §§ 250.800(b), 250.802(b), and 250.841(b).
Response—BSEE included the costs associated with following industry standards as part of the baseline of the economic analysis. Per OMB Circular A-4, which provides guidance to Federal agencies on the preparation of the economic analysis, the baseline represents the agency's best assessment of what the world would be like absent the action. The 1988 final rule is the starting point, and that rule contained a majority of the provisions that are currently found in the regulations.
The baseline should include all practices that reflect existing industry standards and regulations, and that would continue to do so even if the new regulations were never imposed. Industry standards represent generally accepted practices and expectations that are used by the offshore oil and gas industry in their day to day operations. Such standards are industry-developed documents that are written and utilized by industry experts. Thus, even without regulations requiring compliance with the standards, we understand and expect that industry follows these standards to ensure safety and reliability of operations. Therefore, BSEE includes the benefits and costs of utilizing these standards (including API 570) in the economic baseline. This is consistent not only with the guidance provided by OMB Circular A-4, but also with commonly accepted methods within the economic profession and BSEE's approach in previous rulemakings.
The existing subpart H regulations already require compliance with API RP 14J for all new FPSs. Accordingly, costs associated with such compliance are not attributable to this rule. In addition, compliance with API RP 14J is already required in subpart I (§ 250.901(a)(14)) for all platforms. Subpart S also requires hazard analysis under § 250.1911. Although API RP 14J is not specified in § 250.1911, it is an appropriate document to use for compliance with that section in the context of production safety systems. The requirement for hazard analysis is not new; BSEE is only specifying which document to use for certain situations. By following API RP 14J, as incorporated in subpart H, the operator is also complying with the hazard analysis requirement in subpart S (the SEMS regulations) for the relevant systems.
Final § 250.802(b) is based on industry standards (ANSI/API Spec. 14A,
Final § 250.803(b) requires operators to ensure that an investigation and a failure analysis are performed within 120 days of the failure to determine the cause of the failure and that the results and any corrective action are documented. If the investigation and analysis is performed by an entity other than the manufacturer, the final rule requires operators to ensure that the manufacturer and BSEE receive copies of the analysis report.
Final § 250.803(c) specifies that if an equipment manufacturer notifies an operator that it changed the design of the equipment that failed, or if the operator changes operating or repair procedures as a result of a failure, then the operator must, within 30 days of such changes, report the design change or modified procedures in writing to the Chief of BSEE's Office of Offshore Regulatory Programs or the Chief's designee.
Final § 250.803(d) provides the address to which reports required by this section to be submitted to BSEE must be sent.
Comment—One commenter recommended the submission of all failure reporting data to BSEE within 30 days, and that international failures should be included in the analysis. Another commenter suggested that SPPE failure reports be submitted to a third-party organization for review and analysis so that the third party could analyze the information in the failure reports and provide BSEE, operators and manufacturers with assimilated data that would help develop and improve SPPE reliability and SPPE operating best practices.
Response—BSEE agrees with several of the issues raised by these comments and has revised this section in the final rule to require that the written notice of equipment failure, a copy of the analysis report, and a report of design changes or modified procedures be submitted to BSEE as well as to the manufacturer. Specifically, the notice of failure and report of design changes or modified procedures must be provided to the Chief of BSEE's Office of Offshore Regulatory Programs, or to the Chief's designee, and to the equipment manufacturer within 30 days. However, BSEE does not agree that 30 days is a realistic timeframe for the completion of a thorough and meaningful investigation and failure analysis report. Once failure reporting is sufficiently established, BSEE may consider additional reporting requirements. BSEE does not require failure reporting from areas outside the U.S. OCS. BSEE may consider information that is available from operations in other countries, but since would be extremely difficult to ensure consistent reporting of information, at this time, it is unlikely that BSEE would consider it appropriate to consider such information in a formal analysis. In addition, as suggested by a commenter, BSEE may consider designating an appropriate third-party to receive the failure notifications and operators' investigation/analysis reports so that the third-party could analyze the information and provide aggregated data and statistical analyses to industry, BSEE, and the public.
Comment—Commenters suggested that the proposed 60-day timeframe for investigation and failure analysis could be difficult for some manufacturers to meet given their workload. They suggested that there should be some leeway for instances where failure analyses have been requested or are in process, but will not be completed before the 60-day deadline. The commenters also expressed concern that failure or design change reporting may lead BSEE to require all operators to replace a particular model of equipment based on isolated failures of the equipment.
Response—The comment regarding possible difficulties with equipment manufacturers meeting the proposed deadline for failure investigation and analysis is misplaced; the operator is responsible for ensuring the investigation and failure analyses are performed, not the manufacturer. However, BSEE has increased the timeframe to perform the investigation and failure analysis in the final rule to 120 days to accommodate concerns regarding the operator's ability to meet the shorter proposed timeframe. When BSEE receives notification of a design change from the operator, BSEE will work with the operator on a case-by-case basis to ensure that the appropriate actions are taken, including an assessment of whether any equipment changes are warranted by the reported failure(s).
Comment—One commenter stated that the requirement for failure reporting to and from SPPE manufacturers fails to address the reality that a manufacturer may go out of business or be acquired by another firm. The commenter asked what failure reporting procedures must be followed in the event an SPPE manufacturer is no longer in business or is acquired by a different company.
Response—The failure reporting requirements only apply to active businesses. If a manufacturer is no longer in business, the operator may contact BSEE and we will work with the operator on a case-by-case basis. If a business is the subject of a merger or is acquired by another entity, the operator should perform the necessary reporting with the successor company.
Comment—A commenter suggested that BSEE should revise the rule language to clarify that surface-controlled SSSVs are fail-safe automatic valves, and these valves are installed at a fail-safe setting depth that allows for automatic closure under worst-case hydrostatic conditions.
Response—No changes are necessary. The regulations require operators to follow API RP 14B, Recommended Practice for Design, Installation, Repair and Operation of Subsurface Safety Valve Systems. This standard is incorporated in existing subpart H regulations, as well as in this final rule. The provisions of API RP 14B are consistent with the commenter's suggestions. In addition, there are specific requirements for SSSVs throughout subpart H and specific testing requirements under § 250.880.
Comment—A commenter suggested removing language referencing flow couplings from all sections requiring certification of subsurface safety devices as flow couplings are not safety devices. The commenter also recommended that BSEE incorporate by reference API Spec. 14L, Specification for Lock Mandrels and Landing Nipples.
Response—BSEE agrees with the commenter that flow couplings should not be considered a safety device. BSEE updated the section's introductory paragraph to clarify that flow couplings must be installed above and below the subsurface safety device and removed the reference to a flow coupling as part of the subsurface safety device. BSEE continually considers relevant standards for incorporation, but does not always decide to incorporate a specific standard into the regulations. In this case, the design of equipment that the document covers (lock mandrels and landing nipples) are addressed with tubing design in subparts E and F of the existing regulations. Flow couplings prevent wear and reduce the effects of turbulence on SSSV performance and are considered an integral part of the tubing string.
Comment—A commenter suggested that the language indicating that “flow couplings” must conform to the SPPE requirements should be revised. The commenter noted that there are no API or industry standards for flow couplings as they are not safety devices, but rather a manufacturer specific item of equipment. The commenter also stated that flow couplings are not identified as SPPE in proposed §§ 250.801 through 250.803 and recommended removal of the reference to flow couplings.
Response—BSEE agrees with the commenter that flow couplings should not be considered a safety device. However, they must be installed, as provided for in API RP 14B, Recommended Practice for Design, Installation, Repair and Operation of Subsurface Safety Valve Systems. This document is incorporated by reference in this rulemaking in final § 250.802(b) and existing BSEE regulations. Flow couplings prevent wear and reduce the effects of turbulence on SSSV performance and are considered an integral part of the tubing string. BSEE revised this section to remove the reference to flow couplings and suggestion that they are a safety device.
Comment—A commenter recommended eliminating the portion of § 250.813 that allows operators to install a subsurface-controlled SSSV instead of pulling the well tubing and installing the preferred surface-controlled SSSV or, at a minimum, the commenter recommended revising the rule to set a time limit for installation of the preferred surface-controlled SSSV, rather than allowing the operator to produce the well indefinitely without making this change.
Response—No changes to the regulation are needed. Requiring installation of an SSSV that is surface-controlled within a specific timeframe
Comment—A commenter recommended that BSEE revise this section to include: A semi-annual SSSV testing interval in the proposed requirement at § 250.880; a requirement that no leakage during valve testing be detected as evidenced by a stabilized, flat-line pressure response verifying that a well is completely shut-in and isolated; a requirement that an operator notify BSEE of valve testing such that it can send inspectors to observe testing; a requirement that the operator report valve failures to BSEE; and immediate shut-in of wells after a failed test or indication of a failed SSSV.
Response—The regulatory testing requirements for SSSVs under § 250.880, in addition to the testing provisions in API RP 14B, are adequate. SSSVs are part of a closed system contained within the tubing. This system is designed to minimize oil spills by stopping the flow within the tubing in the event that the riser is damaged. BSEE revised this section to reference SSSV testing requirements in § 250.880, clarifying that those testing requirements apply to SSSVs. BSEE conducts regular inspections of facilities. During the inspections, a full review of all testing and maintenance records is usually conducted. BSEE can require the operator to test the SSSV and BSEE may witness the testing during routine inspections, however this authority does not need to be specified in § 250.814.
Comment—A commenter recommended revising proposed §§ 250.814 and 250.815 to specify the alternate setting depth requirements for wells installed in permafrost areas, or wells subject to unstable bottom conditions, hydrate formation, or paraffin problems.
Response—Setting depth is based on site specific conditions. Specifying a single setting depth may not adequately ensure the integrity of the well under all applicable scenarios and environmental conditions. Final §§ 250.814(a) and 250.815(b) allow the District Manager to address the particular circumstances presented in setting depths for wells in areas of permafrost, unstable bottom conditions, hydrate formation, or paraffin problems.
Comment—A commenter asserted that is not clear what purpose is served by the proposed requirement to have a support vessel in attendance if an SSSV is inoperable. The commenter suggested revising the language to remove the reference to support vessels.
Response—No changes are necessary. For a well on a satellite structure, the support vessel is intended to give personnel an escape route in the event of an emergency. If a support vessel is not on site and SSSV is removed, the operator must install a pump-through plug.
Comment—A commenter recommended that BSEE include or incorporate by reference a separate section on valve testing requirements in this section. Existing regulations require SSVs for each well that uses a dry surface tree. The proposed regulations would require compliance with API RP 14H. API RP 14H provides for periodic valve testing at an unspecified frequency. The commenter supported the monthly testing requirement in § 250.880 for this valve and asserted that such a critical valve used to isolate a well in the event of abnormal well conditions or an emergency should not leak at all. Additionally, the commenter recommended requiring the operator to notify BSEE immediately if a valve fails or does not pass a test and to shut in the well until the valve is repaired or replaced.
Response—Section 250.819 in the final rule requires conformance with § 250.803, which addresses failure reporting to BSEE for SSVs. BSEE may request additional failure data if necessary. To clarify the testing requirements for SSVs, BSEE revised the final rule in § 250.820 to reference § 250.880. There is no need to repeat that reference here. The failure reporting requirements follow industry standards as required in final § 250.803. Under final § 250.880(c)(2)(iv), operators must test SSVs monthly and if any gas and/or liquid fluid flow is observed during the leakage test, the operator must immediately repair or replace the valve. API RP 14H allows for some leakage during this test, however, in the final rule, BSEE requires no gas and/or liquid flow during the leakage test. As previously stated, when there is a difference between the regulations and the incorporated standards, the operator must follow BSEE's regulations.
Comment—A commenter stated that the proposed rule did not refer to the testing requirements specified for SSVs as described in proposed § 250.880. The commenter recommended that a reference to § 250.880 should be included in § 250.820.
Response—BSEE revised this section to include the recommended reference to § 250.880.
Comment—A commenter requested clarification as to what constitutes an “emergency” that will require oil wells and gas wells requiring compression to be shut-in.
Response—There a number of different types of emergencies that could necessitate the shut-in of production. The example provided in this section is a specific named storm, and shut-in will be associated with the anticipated storm path. Any number of other emergency circumstances may likewise preclude the safe continuation of production and require shut-in pursuant to this provision. If there are any questions or concerns about whether a particular circumstance requires shut-in, the operator may contact the appropriate District Manager for guidance.
Comment—A commenter requested clarification that BSEE will not allow oil wells and gas wells requiring compression to flow on hurricane or storm timers, and that they must be shut-in before personnel evacuate.
Response—No changes are necessary based on this comment. The regulations set specific requirements for valve closure timing based on the actuation of an ESD or the detection of abnormal conditions. The regulation does not allow operators to use timers to delay the valve closure. In addition, operators must include emergency response and control in their SEMS program under § 250.1918; this should include evacuation and shut-in procedures.
Comment—A commenter requested clarification as to the meaning of “impending named tropical storm or hurricane” and asks whether there will be some cases in which a storm or other meteorological event will not require shut-in.
Response—The description of an impending named tropical storm is one example of an emergency situation when BSEE would require operators to shut-in their wells. In this example, the need for shut-in will be determined by the anticipated storm path and whether it threatens to impact the relevant production operations. The determination as to whether to shut-in a specific facility during a storm event is based on a number of factors, including the proximity of the facility to the storm path, the anticipated wind strength and waves heights, and the design of the facility. The operator must address emergency response and control in its SEMS program, under § 250.1918; this should include the conditions for shut-in and evacuation.
Comment—A commenter noted that the language in this section is specific to dry tree SSVs, but also noted that the proposed text mentions “subsea fields.” The commenter recommended deleting the reference to “subsea fields.”
Response—BSEE agrees with the comment, and removed “or subsea field” from paragraph (b) in the final rule.
Comment—A commenter stated that it is unclear whether proposed § 250.825 would prohibit subsea trees in Arctic operations due to the lack of a provision regarding setting depths in Arctic conditions. If allowed, the commenter recommended that BSEE specify in the regulation the allowable conditions and BSEE explain why the subsea trees would be BAST.
Response—All proposed oil and gas production operations on the OCS are required to have production safety equipment that is designed, installed, operated, and tested specifically for the surrounding location and environmental conditions of operation prior to approval. Under § 250.800(a), the final rule requires all oil and gas production safety equipment to be designed, installed, used, maintained, and tested to ensure the safety and protection of the human, marine, and coastal environments. BSEE understands that the Arctic may have unique operating conditions, however this rulemaking is not Arctic-specific. Although this final rule is intended to address production safety systems in all OCS regions, there are provisions that require the operator to address Arctic-related issues. For example, § 250.800 of the final rule requires operators to use equipment and procedures that account for floating ice, icing, and other extreme environmental conditions for production safety systems operated in subfreezing climates. In addition, BSEE may address Arctic-specific issues through a variety of mechanisms including separate rulemakings, guidance documents, or on a case-by-case basis. As previously explained in response to comments on § 250.107(c), BSEE is not making a BAST determination in this rulemaking, as a whole or for any specific provisions.
Comment—A commenter recommended that the waiver (departure) provisions of § 250.825(b) should be removed from the proposed rule as BSEE does not specify under what circumstances it would allow the installation of subsea tree valves and sensors without testing all the subsea tree valves and sensors. If BSEE does not agree to eliminate the waiver language from the proposed rule, the commenter requested that BSEE explain under what circumstances it would approve a subsea tree to be installed without testing all the subsea tree valves and sensors, and what criteria would be used in BSEE's decision making.
Response—As discussed previously, BSEE has removed the proposed language referring to departure requests under § 250.142 from the final rule. However, the operator may still submit a departure request related to the requirements of this section or any other requirement in the regulations. The provision for departure requests applies to any of the regulations under part 250, which does not need to be specified in individual sections.
Comment—A commenter recommended that BSEE not require “flow couplings” to conform to SPPE requirements since they are not a safety device and there are accordingly no API or industry standards for flow couplings. The commenter also noted that flow couplings are not identified as SPPE in §§ 250.801 through 250.803. The commenter asserted that flow couplings are not safety devices, but rather heavy-walled couplings used in conjunction with some down-hole safety device applications.
Response—BSEE agrees with the commenter that flow couplings should not be considered a safety device. However, they must be installed, as provided in API RP 14B, Recommended Practice for Design, Installation, Repair and Operation of Subsurface Safety Valve Systems. This document is incorporated by reference in this rulemaking and existing BSEE regulations. Flow couplings prevent wear and reduce the effects of turbulence on SSSV performance and are considered an integral part of the tubing string. BSEE revised this section
Comment—A commenter asserted that it is unclear whether proposed paragraph (b) requires the testing of all of the valves and sensors on the subsea tree, in addition to the SSSV, or only those valves that are designated as USVs, and the related pressure test sensors. The commenter noted that § 250.880(c)(4) establishes that these valves must pass the applicable leakage test prior to departure of the rig or installation vessel.
Response—Under this section the operator must test all of the valves and sensors associated with the subsurface safety devices before the rig or installation vessel leaves. If the valve was tested and passed after installation of the subsea tree, then that test is valid and the operator does not have to test again until required to conduct valve testing at regular intervals under § 250.880.
Comment—A commenter asserted that “flow couplings” need not conform to the SPPE requirements since there are no API or industry standards for flow couplings and they are not a safety device. The commenter also noted that flow couplings are not identified as SPPE in §§ 250.801 through 250.803.
Response—BSEE agrees with the comment that flow couplings should not be considered a safety device and revised this section to remove the inclusion of flow couplings as a safety device. However, they must be installed, as provided for in API RP 14B, Recommended Practice for Design, Installation, Repair and Operation of Subsurface Safety Valve Systems. This document is incorporated by reference in this rulemaking in final § 250.802(b) and existing BSEE regulations. Flow couplings prevent wear and reduce the effects of turbulence on SSSV performance and are considered an integral part of the tubing string.
Comment—A commenter stated that it is not clear how to interpret the proposed “on site” requirement with respect to surface controls for subsea wells.
Response—BSEE agrees that the proposed language was potentially unclear and revised this section in the final rule to clarify that the surface controls must be located on the host facility.
BSEE also revised final paragraph (b) to clarify that the well must not be open to flow while an SSSV is inoperable, unless specifically approved by the District Manager in an APM. The final rule also revised paragraph (c) by adding a reference to § 250.880 for additional SSSV installation, maintenance, repair, and testing requirements.
Comment—A commenter recommended that BSEE include language requiring operators to shut-in a well if an SSSV is inoperable as well as language eliminating the possibility of an exception to this requirement.
Response—BSEE does not agree with the suggestion that it should never allow exceptions to this shut-in provision. There may be times where an exception to this provision is warranted and appropriate. However, the operator must request an exception from BSEE in an APM, provide justification for that exception, and secure BSEE approval.
Comment—A commenter suggested that BSEE should add language to this section that allows for temporary flow during routine operations and well troubleshooting. The commenter recommended revising proposed paragraph (b) to read, “The well must not be open to flow while an SSSV is inoperable once the subsea tree is installed or BSEE has approved the specific operation that requires flow with an inoperable SSSV.”
Response—No changes are necessary. BSEE does not consider flowback of a subsea well through production equipment that has not been approved by BSEE to be a routine operation. Existing § 250.605 statesthat the operator cannot commence any subsea well-workover operations, including routine operations, without written approval from the District Manager. Temporary flowback of a subsea well may involve the use of non-dedicated production equipment, or production
Comment—A commenter asserted that the formula provided in this section cannot be used for any well other than a dry gas well and that there is no method to measure the leakage in a subsea well. The commenter stated that subsea well leakage must be calculated and may vary with tree configuration or tree (USV) valve leakage or failure.
Response—BSEE does not agree that the formulas required by this section, through incorporation of API RP 14B, are inappropriate for subsea wells. API RP 14B describes the required testing procedures, including any formulas that are needed for calculating leakage rates. If the operator has additional questions about calculating a particular leakage rate, the operator can contact the appropriate District Manager.
Comment—A commenter stated that there are multiple ways to test an SSSV in a subsea well, and that it is not necessarily the case that the test procedure will be as outlined in Annex E of API RP 14B. The commenter recommended modifying the proposed language to indicate that there are acceptable alternative test methods. The commenter also stated that the proposed rule does not directly refer to the testing requirements specified for subsurface safety equipment as described in § 250.880 and suggested adding a reference in final § 250.828(c) to § 250.880.
Response—BSEE agrees with the suggestion to add a reference to § 250.880 for SSSV testing in final § 250.828(c) and has done so. However, it is not necessary to add the suggested language regarding acceptable alternative methods, since an operator may submit a request to the District Manager to use an alternate test procedure under existing § 250.141.
Comment—A commenter recommended revising the proposed language to require operators to maintain, inspect, repair, and test all SSSVs in accordance with the Deepwater Operations Plan (DWOP) or API RP 14B. The commenter also suggested removing proposed § 250.829(a)(3)(ii) since the reference pressure sensor is normally internal to the subsea control module, used for housekeeping only, and it may not be available to the topside system.
Response—The commenter's first concern is addressed in § 250.828(c) of the final rule, which requires compliance with the DWOP and API RP 14B. It is not necessary to restate those requirements here. With respect to the commenter's second concern, BSEE understands that there may be situations where another approach would be appropriate and, in such cases, the operator may request approval to use an alternate procedure under § 250.141.
Comment—A commenter stated that this section is unnecessary because the process to repair or modify a subsea pipeline must be approved by BSEE's GOM Regional Pipeline Section.
Response—BSEE disagrees with the comment. Without an umbilical, the operator is unable to monitor casing pressure and test USVs. The existing pipeline regulations (subpart J) do not address the issues related to testing of the valves or the monitoring of casing pressure that are relevant and necessary to this rulemaking under subpart H. The operator needs to test these valves for functionality and leakage rate, and be able to monitor for sustained casing pressure. The physical alteration or disconnection of the subsea flowline system, including the umbilical, may require submission of a pipeline permit application to the Regional Supervisor. However, those actions address different considerations than are addressed by this section.
Comment—A commenter suggested removing the proposed prohibition against altering or disconnecting the pipeline or umbilical until a repair or replacement plan is approved. The commenter also asserted that this proposed requirement would affect subsea operations and impose new reporting and review requirements on industry.
Response—BSEE does not agree that the suggested changes are necessary. BSEE reviews and approves system alterations to ensure compliance with other regulations. Without an umbilical, the operator is unable to monitor casing pressure and test USVs as required under existing § 250.520; thus, BSEE must have an operator's plans for maintaining compliance with this requirement before the operator disconnects. If the operator's proposed operation of disconnecting/removing flowline/umbilical would cause the operator to be unable to perform required testing on the subsea well, then the District Manager must be involved.
Comment—A commenter recommended that BSEE define the term “Alternate Isolation Valve (AIV),” as it is not a term generally used in the industry or defined in any of the relevant standards, such as API Spec. 6A or API Spec. 17D. The commenter stated that the BSEE regulations need to fully define the term in the regulations so that it is clear which valves the operator must describe.
Response—An AIV is any valve, in addition to the primary and secondary USVs, that acts as the USV. There are multiple names for an AIV, including “flowline isolation valve.” This term was used to emphasize that any valve in the subsea system that may act as a USV must meet the same requirements as the primary and secondary USV. BSEE did not make any significant changes to the proposed regulation with respect to this issue so as not to artificially limit the scope of the term “flowline isolation valve.”
Comment—A commenter recommended revising the language of this proposed section to reflect that there are cases in which redundant USVs are installed. The commenter recommended revising the proposed language to require operators installing redundant USVs to designate one USV on a subsea tree as the primary USV and to install that valve upstream of the choke valve.
Response—No changes are necessary. This provision in the proposed rule, as carried forward into the final rule, already addressed the situation in the manner described by the commenter. Final § 250.833(b) addresses the requirements for redundant USVs.
Comment—A commenter recommended that the new regulation be consistent with the intent of the existing NTL No. 2009-G36, which requires only the primary USV (USV1) to pass the leak test criteria, given that secondary valves are not required by the regulations. The commenter asserted that testing secondary USVs to the same standard as the primary USV should not be required until a secondary USV becomes a primary USV. The commenter also recommended that BSEE include a reference to § 250.880 in § 250.834, as the proposed regulatory language did not directly refer to the testing requirements specified for USVs described in § 250.880.
Response—BSEE agrees with the commenter and has revised final § 250.834 to require the operator to
Comment—A commenter requested clarification on the BSDV location requirement for floating facilities. Another commenter recommended using the current draft language from API 14C for BSDV location and allowing engineering discretion in determining the appropriate location with respect to FPSs. The commenter stated that the prescriptive language of the proposed rule would limit flexibility in the DWOP process and proposed alternate language regarding the BSDV's location.
Response—No changes are necessary. The location of the BSDV was specified in the proposed rule, and is included in the final rule, to ensure the safety of the facility. Under § 250.835(c), when the pipeline riser boards the facility, it must be equipped with a BSDV installed within 10 feet of the first point of access to that riser. Because the BSDV is crucial to the facility's safety, the final regulations (§§ 250.836 and 250.880) seek to ensure its reliability by requiring more stringent testing (
Use of BSDVs (§ 250.836)
Comment—Commenters stated that the proposed requirement to repair or replace a leaking BSDV before resuming production is not consistent with the requirement to immediately repair or replace the valve, as stated in proposed § 250.880(c)(4)(iii). Also, given the potential safety implications associated with a leaking BSDV, commenters recommended that a leaking BSDV should be required to be repaired or replaced before resuming production on any manned facility. The commenters recommended that the language be consistent with proposed § 250.880(c)(4)(iii).
Response—BSEE agrees with the comment that this provision should be consistent with § 250.880(c)(4)(iii) and has revised the final rule to require that the operator immediately repair or replace a BSDV if it does not operate properly.
Comment—A commenter stated that no amount of detail in the regulations will address all concerns, and that rules cannot be revised or updated in a timely manner. The commenter suggested that BSEE hold operators accountable for emergency planning consistent with their management systems and the types of facilities they operate.
Response—BSEE agrees that no amount of detail in the regulations will cover all concerns; however, that does not negate our obligation to continuously improve the regulations in order to protect personnel safety and the environment. BSEE included this provision to provide direction and clarity for operators with regard to certain reoccurring events. BSEE's existing regulations contain other provisions for emergency planning, including a requirement that operators address emergency response and control in their SEMS plans under subpart S of this part (
Comment—A commenter suggested that the process for establishing the geographic impact of an emergency requiring shut-in for oil and compression gas wells is unclear.
Response—The geographic impact of any given emergency will be highly dependent on the fact-specific nature of that emergency. As used in this section, tropical storms are just one example of an emergency; there may be other types of emergencies that require shut-in. In the event of a specific (
Comment—Several commenters suggested that the term “impending named tropical storm or hurricane” needs to be better defined because some named storms would not necessarily require shutting in. Commenters stated that, if the term is meant only as an example of an emergency and is not meant to be all-inclusive, then the language and title of the proposed rule should be clarified or changed. The comment suggested regulatory language providing that BSEE would not need to require operators to shut-in some subsea wells (such as wells with a subsurface safety device) during a storm.
Response—BSEE does not agree with the commenters' suggestions. Changing the title would potentially confuse the scope of this regulation since tropical storms and hurricanes are only examples of emergencies that could require shut-ins; other, non-storm emergencies could also require shut-ins. If an operator has any questions or concerns about whether or when to shut-in as a result of a specific storm or other emergency, the operator may contact the appropriate District Manager for guidance. BSEE also disagrees with the suggestion that wells with subsurface safety devices need not be shut-in during a storm when other wells are shut-in. In fact, all producing wells have subsurface safety devices of some kind, so the commenter's suggestion could result in no wells being shut-in during a storm. This would be contrary to longstanding and accepted safety practices.
Comment—A commenter stated that the proposed language presupposes that the company under whose direction a MODU or workover vessel is operating is the operator responsible for any wells that may be subject to suspension of production. The commenter asserted that such responsibility should only be placed with the lease operator, notwithstanding the proposed rule's apparent assignment of responsibility with the MODU operator. The commenter suggested that BSEE revise the proposed wording in order to place the burden on the operator of producing subsea wells to take action when a MODU or other type of workover vessel is in the area.
Response—BSEE does not agree that the suggested changes are needed. This regulation is primarily directed at the lease operator. However, under § 250.146(c), those persons actually performing an activity subject to part 250 are jointly and severally responsible for compliance with those requirements; this includes the lessee, the operator, and the person actually performing the activity. This would include a MODU operator if that MODU operator is performing activities subject to regulation under part 250. Thus, it is important that the relevant parties coordinate their activities, as well as their communication and control procedures, to ensure compliance with the applicable regulatory requirements.
Comment—A commenter asserted that the term “driller” as used in the proposed language is ambiguous and requires further clarification. The commenter stated that “driller” is not defined in the BSEE's regulations, is overly prescriptive, and is subject to multiple interpretations, including either the drilling contractor or the person serving in the position known as the “driller” on the MODU. The commenter suggested that the wording could also be interpreted as precluding an “assistant driller,” “toolpusher,” or others, from taking action to initiate the needed shutdown.
Response—BSEE agrees with the commenter and has revised this section of the final rule to add “(or other authorized rig floor personnel)” after “driller.”
Comment—A commenter suggested that, for consistency with existing §§ 250.406(a), 250.503, and 250.603, the reference to “ESD on the well control panel located on the rig floor” be changed to “ESD station near the driller's console or well-servicing unit or operator's work station.” The commenter noted the importance of communicating with others in order to shut-in other potentially affected wells, and stated that such information should be identified in the plan submitted to BSEE for approval in advance of operations. The commenter also noted that the proposed wording presupposes that only a single facility's wells could be affected and seemingly fails to place an obligation on that facility's operator (or the operator of any potentially affected wells on other facilities) to shut-in the wells under their control upon receiving notification from the MODU or workover vessel.
Response—BSEE agrees with the commenter's suggestion regarding placement of the ESD station and has changed the text in final § 250.837(b)(2) to refer to the ESD station near the driller's console. For securing the other wells on the platform, the operator
Comment—A commenter recommended that wherever the term “MODU” appears in proposed § 250.837, it should be replaced by the term “MODU or vessel.” The commenter also stated that it is not clear that the requirement to shut-in all wells could be triggered by a dropped object in the event that communication is lost between the MODU or vessel and the platform for twenty minutes or longer. The commenter asserted that the shut-in needs to be implemented from the platform, and suggested that the shut-in requirement does not need to be applied to a well that is under the direct control of the MODU/vessel itself. The commenter also indicated that the requirement to shut-in should be reversed as soon as reliable communication is re-established between the MODU/vessel and the platform.
Response—BSEE agrees with the commenter's suggestion for changing the references to “MODU,” and has replaced that term throughout this section with “MODU or other type of workover vessel,” as used in the introductory sentence in proposed paragraph (b). BSEE also agrees that the shut-in needs to be implemented from the facility; however, that fact does not support the commenter's suggestion that the shut-in requirements should not apply to a well under direct control of a MODU. (In fact, such a well should be shut-in already, since the MODU would be there to work on the well.) As stated in paragraph (b)(2), all wells that could be affected by the dropped object—whether under control of a MODU or other workover vessel or of a platform—must be shut-in to prevent a spill.
With regard to the comment regarding reversal of a shut-in, BSEE agrees that a shut-in can be reversed once communication is restored and the District Manager approves resumption of operations.
Comment—A commenter recommended that the word “rig” and the term “MODU” be replaced by “MODU/offshore support vessel” throughout this section.
Response—BSEE generally agrees with this comment and has replaced the terms “rig” and “MODU” with “MODU or other type of workover vessel” throughout this section of the final rule. This revision is also consistent with the terminology in final § 250.839.
Comment—A commenter asserted that proposed paragraph (b) was confusing in that it would require an operator that has not lost communication with its rig or platform to comply with the maximum allowable valve closure and hydraulic system bleed requirements listed in that paragraph's table. The commenter recommended revising the language to require compliance with the valve closure times and hydraulic bleed requirements listed in either the table or in an operator's approved DWOP, as long as communication is maintained.
Response—BSEE agrees with the commenter's suggested language, which is consistent with BSEE's original intent. Accordingly, BSEE has revised paragraph (b) in the final rule to require that the operator must comply with the maximum allowable valve closure times and hydraulic system bleeding requirements listed in the table or the operator's approved DWOP, as long as communication is maintained.
Comment—A commenter suggested revising the language in proposed § 250.838(b)(2) (Pipeline pressure safety high and low (PSHL)) to provide the same requirements for bleeding both high pressure (HP) and low pressure (LP) hydraulic systems. The commenter also suggested adding language to proposed § 250.838(b)(4) in order to prevent a surface-controlled SSV from closing on a flowing well, since the HP system will vent faster than the LP system.
Another commenter suggested revising the language in proposed § 250.838(d)(2)—(Pipeline PSHL) to require a shut-down time that is determined by hydraulic analysis and confirmed during commissioning instead of using the times specified in that paragraph. The commenter asserted that it is difficult to close valves in 5 minutes on most deepwater, long step-out systems.
In addition, the commenter suggested revising the proposed requirement in § 250.838(d)(5) (Dropped Object—subsea ESD (MODU)) to “initiate unrestricted bleed immediately” upon communication loss for both LP and HP systems because that action would almost always result in the surface-controlled SSV closing on a flowing well. Specifically, the commenter requested that BSEE add language to this paragraph specifying that the LP hydraulic system must be vented and valves closed before the HP system is vented.
A commenter asserted that the table of valve closure and hydraulic bleeding requirements in proposed paragraph (b) should be consistent with the table in NTL No. 2009-G36, which explains what to do in case an operator cannot meet valve closure times when it has a loss of communications. The commenter stated that the table in § 250.838(d) requires immediate closure of tree valves upon Subsea ESD (MODU), and asserted that some control systems cannot meet that timing requirement, especially with regard to the LP system.
Response—BSEE agrees with the suggestion to revise the table to be consistent with NTL No. 2009 G-36 and
Comment—A commenter recommended that the term “MODU” be replaced by “MODU/offshore support vessel” throughout this section.
Response—BSEE agrees and has changed the term “MODU” to “MODU or other type of workover vessel” in final paragraph (b)(5). This revision is also consistent with the terminology in final §§ 250.837 and 250.838.
Comment—A commenter stated that the OCS Platform requirements in the proposed section did not specify any manning requirements and asserted that the regulations should include specific manning requirements for Arctic OCS facilities and should prohibit unmanned facilities.
Response—Appropriate crewing is a facility—and operation-specific issue. As previously stated in part IV.B.3, BSEE understands that the Arctic OCS presents unique operating conditions and other challenges. BSEE recently addressed exploratory drilling requirements for the Arctic OCS in a final rule published on July 15, 2016 (81 FR 46477), and BSEE may address other Arctic-specific issues in future rulemakings, guidance documents, or on a case-by-case basis.
Comment—A commenter asserted that limiting the duration of temporary piping repairs to 30 days could be problematic since a significant fabrication or construction backlog could hinder final repairs. The commenter also stated that weather and logistics will play a key role when the permanent repair is actually being conducted; thus, it may take more than 30 days to complete the permanent repair. The commenter suggested adding language to this provision to allow the District Manager to approve extensions to the duration of a temporary repair in 30-day increments. Another commenter requested clarification on whether the 30-day limit on approvals of the duration of temporary repairs to facility piping is only for piping in hydrocarbon service or for all facility piping.
Response—BSEE does not agree that the suggested changes are appropriate. BSEE considers pressures, type of systems, and other factors in considering requests for approval of temporary repairs to piping. The longer the temporary repair is in place, the greater the risk that the repair will fail, given that the temporary repair material is generally not designed for long-term use in accordance with industry standards for permanent piping (
Comment—A commenter stated that although this proposed section would require compliance with specific standards for OCS platforms, the term
Response—As previously explained, BSEE understands that the Arctic presents some unique situations, and BSEE may address Arctic-specific issues in future rulemakings, guidance documents, or on a case-by-case basis. In the meantime, adding a definition of “platform,” particularly one addressing Arctic-specific circumstances, is beyond the scope of this rulemaking. However, when BSEE reviews a permit, it considers the specific operating and environmental conditions. Gravel islands are different from platforms in several ways, and may need to meet different requirements or permit conditions. If there are any questions concerning the applicability of this final rule to gravel islands, the operator should contact the appropriate District Manager for evaluation on a case-by-case basis. (For activities on the Arctic OCS, any reference in this part to District Manager means the BSEE Regional Supervisor for the Alaska region.)
Comment—One commenter stated that this section should not refer to API 570 because that standard was developed for downstream operations, not offshore oil and gas upstream operations. Thus, the commenter asserted that there would be many potential conflicts if that document were applied to offshore operations as proposed. The commenter recommended that, before the document is incorporated in its entirety, BSEE review the document and determine what sections are applicable to offshore production operations.
Response—BSEE disagrees with the comment. API 570 is the industry standard for piping. Although API 570 was developed primarily for the petroleum refining and chemical process industries, it states that it may be used for any piping system. Moreover, the commenter did not assert any specific conflicts related to using API 570 for offshore production operations. In fact, this document is extensively cited and widely used by the offshore oil and gas industry, especially with respect to inspection of piping (
Comment—A commenter suggested adding language to proposed § 250.841(b) to clarify that API 570 applies downstream of the boarding valve for design requirements and to clarify the types of facility piping to which the provisions regarding temporary repairs will apply.
Response—BSEE does not agree that the suggested additions are necessary. The proposed and final regulatory text for § 250.841(b) refers to “production process piping.” Subpart H applies to any piping confined to a production platform that is downstream of the BSDV. Piping upstream of the BSDV is covered by the pipeline regulations, under subpart J. In addition, as previously stated, the provisions regarding temporary repairs apply to all facility piping.
Comment—A commenter asserted that BSEE should limit the requirements under paragraph (b), as applied to floating facilities, to equipment/systems and piping over which BSEE has jurisdiction.
Response—BSEE does not need to revise paragraph (b) as suggested. These regulations apply only to operations that are under BSEE authority. This regulation ensures that operations with respect to platform production facilities and platform production process piping are conducted in a manner that prevents or minimizes the likelihood of fires (
The final rule also requires completion of a hazards analysis during the production safety system design process and requires a hazards analysis program to assess potential hazards during the operation of the platform. The final rule also requires that the designs for mechanical and electrical systems be reviewed, approved, and stamped by a registered professional engineer (PE). It also requires that a registered PE certify the as-built piping and instrumentation diagrams (P&IDs). This section also specifies that the PE must be registered in a State or Territory of the U. S. and have sufficient expertise and experience to perform the applicable functions.
Final § 250.842 requires that operators certify that all listed diagrams (including P&IDs) are correct and accessible to BSEE upon request, and that the required as-built diagrams outlined are submitted to the District Manager within 60 days after production commences.
In addition, final § 250.842(b)(3) includes a reference to the hazards analysis requirement of § 250.1911 and, as discussed in the proposed rule, imposes a requirement that the operator certify that it performed a hazard analysis during the design process in accordance with API RP 14J and that a hazards analysis program is in place to assess potential hazards during the operation of the platform.
Comment—A commenter raised questions about BSEE and USCG jurisdictional areas of responsibility over electrical systems.
Response—The comment was unclear. The requirements of § 250.842 address what information must be included in a production system safety application. These regulations apply only to operations and systems that are under the authority granted to the Department by OCSLA. More detailed discussion of BSEE's and USCG's jurisdiction is found in part IV.B.2 of this document.
Comment—One commenter suggested that the final rule should specifically require a U.S.-registered professional mechanical engineer to stamp all mechanical system designs, and require a U.S.-registered professional electrical engineer to stamp all electrical system designs.
Two commenters, however, suggested revising proposed § 250.842(b)(2) to allow chartered engineers or other non-U.S. engineers to design, review and approve mechanical and electrical systems because a large number of floating structures are engineered and built outside the U.S. The commenter asserted that the proposed wording could introduce significant legal issues when applied to modifications on existing facilities. The commenters recommended that BSEE revise paragraph (b)(2) to address these issues. Another commenter supported the proposed requirement that PEs be registered by a State or Territory, but requested that BSEE expressly state that the term “sufficient expertise and experience” for PEs includes experience with Arctic and harsh environments for systems used in the Arctic region.
Response—With regard to the first commenter's suggestions, BSEE agrees that proposed § 250.842(d) was potentially overbroad. Therefore, in the final rule, we have revised § 250.842 by inserting the words “an appropriate” before “registered professional engineer” to clarify BSEE's intention that the registered professional engineer be qualified in the particular discipline relevant to the certification, (
With regard to the suggestions to allow non-U.S. registered engineers to perform tasks under paragraph (b)(2), no changes are necessary based on these comments. A reliable verification, with stamping, by a registered PE of the designs for the mechanical and electrical systems is important to BSEE's decisions regarding the suitability of a proposed production safety system, and BSEE has no way of verifying a registered PE stamp from a foreign country.
With respect to the commenter's assertions about existing facilities, this regulation is tailored to improve production process safety without unreasonably burdening the industry. In addition, although the commenter indicated that the proposed rule could create significant legal issues when applied to existing facilities, the commenter failed to specify what those legal issues might be, and it is not clear why application of this regulation to existing facilities would raise any significant legal issues. The relevant portion of proposed § 250.842(b)(2), to which this comment was directed, requires that the production safety system application include a certification that the mechanical and electrical systems designs were reviewed, approved, and stamped by an “appropriate” registered PE. Given the importance of the certifications required by final § 250.842(b), BSEE did not make any significant changes to this proposed regulation based on this commenter's suggestions.
BSEE did not revise paragraph (b)(2) to add language regarding experience with Arctic environments. BSEE intends that the requirement that an appropriate PE have “sufficient expertise and experience” will include experience with conditions where the operations will take place, including the Arctic environment for Arctic operations. As discussed earlier, BSEE may address specific Arctic-related issues in separate rulemakings, guidance or documents in the future.
Comment—A commenter asserted that the requirement in proposed paragraph (a)(1), to include a schematic piping and instrumentation diagram in the operator's production safety system application, would add unwarranted burdens to keep such diagrams updated. To reduce the asserted burden, the commenter recommended deleting proposed paragraphs (a)(1)(i) and (a)(1)(iii) regarding well shut-in tubing pressure and pressure safety valve (PSV) set points, respectively. The commenter stated that shut-in tubing pressure and PSV set points change often, and thus would require resubmitting updated drawings to BSEE frequently. The commenter suggested that this reporting burden would not provide additional value.
Response—BSEE does not agree that the suggested change is necessary. BSEE does not expect operators to submit drawings every time the shut-in tubing pressures or PSV set points change, unless the production safety system changes as a result (
Comment—One commenter noted that proposed § 250.842(a)(1)(ii) would have required that piping specification breaks be included on a schematic piping and instrumentation diagram, whereas BSEE District Engineers currently accept system pressure specification breaks, as opposed to individual “piping” specification breaks, for Safety Analysis Flow Diagrams (SAFDs). A commenter provided an example involving the compressor skid. According to the commenter, using piping specification breaks would yield a wide variety of breaks (
Response—BSEE does not agree with the commenter's suggested change. The piping specification breaks provide BSEE with important information for its review of the schematics and diagrams to ensure that the safety system has been properly designed to account for changes in the piping design (
Comment—One commenter noted that, under proposed § 250.842(a)(1)(ii) and (a)(2), the Appendix E requirements of API RP 14C for the SAFD reflect the need for maximum pressures to be shown for pressure vessels, pipelines and heat exchangers. The commenter questioned whether, since this new requirement applies to piping and instrumentation diagrams, combining the two documents (
Response—BSEE does not agree with the commenter's suggestion for combining these two documents. The operator needs to submit both P&IDs and SAFDs. Industry already has standards in place for both documents and each document includes valuable information that is not found in the other. BSEE may consider a combined document in the future, as suggested, if industry establishes a standard process safety flow diagram that contains all of the information that BSEE otherwise would receive in P&IDs and SAFDs.
Comment—A commenter stated that he requirement in proposed paragraphs (a)(1) and (2) to maintain two sets of drawings would be burdensome and create opportunities for errors and omissions to occur. A commenter noted that the preamble of the proposed rule referred to the
Response—BSEE does not agree with this suggestion. The importance of correct as-built documents and professional engineer stamps was highlighted in the
Although the
• Stamping of engineering documents by a registered PE;
• Certification by the operator that all listed diagrams, including P&IDs, are correct and accessible to BSEE upon request; and
• Submittal of a certification to the District Manager, within 60 days after production begins, that the “as-built” diagrams, as described in final § 250.842(a)(1) and (2) are on file and have been stamped by an appropriate PE.
Comment—A commenter recommended removing proposed paragraph (a)(3)(ii) from the final rule, asserting that the term “potential ignition sources” is ambiguous and that the value of the additional information is not apparent.
Response—BSEE disagrees. This information (
Comment—One commenter asserted that the requirement in proposed paragraph (a)(3)(iii) for one-line electrical drawings for all electrical systems would be an expansion of existing requirements and requested that BSEE limit final paragraph (a)(3)(iii) to submittals for new facilities only.
Response—BSEE disagrees. Proposed and final § 250.842(a)(3)(iii) retains, and does not expand the scope of, the information required by existing § 250.802(e)(4)(ii), and operators are already complying with that longstanding requirement. This section of the final rule only moves the current requirements to a new section. BSEE did not propose, and has not made, any substantive revisions to the existing regulatory requirement.
Comment—A commenter recommended that BSEE limit the expanded requirement under proposed paragraph (a)(4) (schematics of fire and gas-detection systems) to submittals for new facilities only.
Response—BSEE disagrees with the requested limitation. This information is already required by existing § 250.802(e)(6), and this final rule simply moves that longstanding requirement to a new section, with no substantive changes. Operators are already complying with the existing requirement and BSEE sees no need or justification for limiting its scope to new facilities.
Comment—One commenter noted that proposed paragraph (b) would require “designs for the mechanical and electrical systems . . . [to be] reviewed, approved, and stamped by a registered professional engineer(s).” The commenter asserted that a vital component of the process safety system is the implementation of appropriate safety and control programming logic in either pneumatic panels or programmable logic controller (PLC) processors, much of which is carried out by equipment suppliers and/or programmers not directly supervised by registered engineers. The commenter recommended adding a definition for “designs” in the final rule.
Response—BSEE disagrees with that recommendation. Adding a definition of “designs” in this section is not necessary and would not substantially clarify the content of the regulation. The terms used in paragraph (b), including “designs,” are well-established and commonly used in the affected industry, and have long been used in the existing regulations in the same context as they are used in this rulemaking.
Comment—A commenter recommended rewording paragraph (b)(2) to allow for an electronic review by a PE in lieu of requiring that hard copies be stamped. The commenter asserted that the proposed wording of paragraph (b)(2) could also create significant ambiguity when applied to modifications on existing facilities. The commenter suggested that stamping and/or certification be limited to new systems/designs that are “to be installed.”
Response—No changes are necessary. Electronic stamps of a registered PE are acceptable under this section, as long as they provide the same authentic verifiable information as a PE stamp applied to paper. For example, the electronic stamp could be a jpeg of the PE stamp, depending on what each state allows its registered engineers to do. Regarding the assertion of potential ambiguity if the PE review requirement is applied to modifications of existing equipment, the commenter failed to provide any support for that assertion, and BSEE is not aware of any ambiguity that warrants changing the applicability of this requirement to modifications to existing equipment in addition to installation of new equipment.
Comment—A commenter proposed that BSEE change proposed paragraph (b)(2) to require that the designs for the mechanical and electrical systems be reviewed, approved, and stamped by an independent third-party. The commenter suggested that independent third-party organizations have the multi-disciplinary knowledge to fully evaluate the safety of a complete production system and can demonstrate to regulators that they have comprehensive quality and work processes and training and qualification programs for their employees.
The commenter also asserted that, as BSEE moves to incorporate risk principles into its safety regime, DNV GL's Offshore Service Specification DSS-OSS-300, Risk Based Verification, may help BSEE and industry achieve their safety objectives. The commenter noted that, in general, verification based on risk is founded on the premise that the risk of failure can be assessed in relation to an acceptable risk level and that the verification process can be used to manage that risk, thus making the verification process a tool to maintain the risk below the acceptance limit. The commenter also suggested that verification based on risk helps to minimize additional work and cost, while maximizing risk management effectiveness.
Response—No changes are necessary. Paragraphs (b)(2) and (d) require certification that an appropriate registered PE has stamped the design documents, which is intended to implement one of the recommendations in the
As to the commenter's second suggestion, the requirements in paragraph (b)(2) represent a practical and effective means of verifying that the mechanical and electrical systems have been designed properly to perform their critical functions in a manner similar to the longstanding requirement under existing § 250.802(e)(5). Thus, BSEE does not agree with the commenter's suggestion that the approach taken by this final regulation may cost too much or fails to manage risks appropriately. BSEE also does not agree that the commenter's suggested “risk-based” approach would minimize costs and maximize risk management. However, BSEE is continually evaluating risk-based methods to improve safety and environmental protection, and BSEE may consider at a later date whether an alternative risk-based approach to system design verification is warranted.
Comment—A commenter requested, for purposes of proposed paragraph (b)(2), that BSEE accept the review and approval by a classification society of the mechanical and electrical systems as equivalent to the review, approval and stamping of systems designs by a registered PE. The commenter based this request on BSEE's existing regulations at § 250.905(k), which provide for review, approval and certification by a “classification society” as an alternative to the same functions performed by a registered PE under that section. The commenter asserted that the USCG also recognizes review and approval by classification societies as equivalent to the certification by a registered professional engineer. A second commenter made similar statements and requested that BSEE revise this section to allow “certification authorities,” in lieu of registered PEs, to review, approve and stamp mechanical and electrical system designs. The commenter provided no examples or criteria for identifying any certification authorities.
Response—No changes are necessary. A classification society or a “certification authority” could be used by an operator to review and approve the relevant design documents as long as the classification society or certification authority provides a qualified, registered PE to review, approve, and stamp the documents. However, for the same reasons discussed in response to the preceding comment (regarding independent third-parties), BSEE does not have reason to believe at this time that review and approval by a classification society or certification authority, without use of an appropriate registered PE, would provide the necessary level of confidence that the mechanical and electrical systems are properly designed to perform their critical roles in the production process safety system. However, if an operator believes that an alternative review and verification process involving a classification society or certification authority would be at least as effective as the regulatory requirement for use of a registered PE, it may request BSEE's approval of such an alternate procedure on a case-by-case basis under § 250.141.
Comment—A commenter suggested that proposed paragraph (b)(2) should be revised to clarify whether these provisions apply to all electrical and
Response—BSEE does not agree that the suggested changes are necessary. Paragraph (b)(2), as proposed, clearly applies to all mechanical or electrical systems that are included in the operator's production safety system application for approval. Monograms are not a substitute for PE review and verification because monograms only represent that the system was in compliance with the standard at the time of manufacture; they do not provide any information about any post-manufacture changes made to the system. BSEE needs to verify, however, that the drawings are accurate for the systems and equipment that are actually installed on the facility. Thus, final paragraphs (b)(2) and (d) require certification that a registered PE stamped the actual documents.
Comment—A commenter asserted that the hazards analysis specified by proposed paragraph (b)(3) would require more detail than a similar requirement for the operator's SEMS program. The commenter suggested that BSEE clarify how paragraph (b)(3) and the SEMS hazards analysis requirements complement or differ from each other, with the ultimate goal of establishing one standard for hazards analysis.
Another commenter asserted that the placement of the hazards analysis requirement in § 250.482(b)(3) is confusing given that hazards analyses are covered by the subpart S (SEMS) regulations, API RP 75, and API RP 14J, and suggested that any alterations to hazards analysis requirements should be made through revision of subpart S or the industry standards. The commenter also asserted that the reference to “during the design process” in proposed paragraph (b)(3) is vague and potentially confusing with respect to whether it is referring to the original design process or to the design process of a modification. The commenter recommended removing “the “design process” from the final rule. The commenter also recommended that BSEE delete paragraph (b)(3) entirely or revise paragraph (b)(3) to read: “You must certify that a hazard analysis was performed in accordance with subpart S and API RP 14J (incorporated by reference as specified in § 250.198), and that you have a hazards analysis program in place to assess potential hazards during the operation of the platform.”
Response—BSEE agrees, in part, with these comments and has revised final paragraph (b)(3) to state that the operator must certify that its hazards analysis was performed in accordance with § 250.1911 and API RP 14J, and to clarify that the operator must have a hazards analysis program in place to assess potential hazards during the operation of the facility. BSEE also deleted the proposed requirement to perform the analysis “during the design process.” These revisions clarify that the hazards analysis required by this paragraph must satisfy the SEMS requirement, with respect to the relevant safety systems, as well as the more specific analysis required by API RP 14J. This will result in hazards analyses under subpart H that are consistent with the subpart S requirements, but that likely will provide more specific details regarding the relevant safety systems than subpart S alone might require.
Comment—A commenter recommended that BSEE allow certification of mechanical and electrical systems installation through other means than a letter from the operator.
Response—No changes are necessary. Final § 250.842(d) calls for the operator to submit a letter certifying the accuracy of the as-built drawings. The letter provides documentation to assist BSEE in verifying that the drawings are consistent with the mechanical and electrical systems. Within 60 days of first production, the operator must submit updated as-built drawings along with a certification that a PE reviewed and stamped these drawings. These written documents will help BSEE ensure that the system was built according to the original plan submitted to BSEE. However, an operator may submit the certification letter electronically, if it chooses, or through BSEE's e-facility safety system permitting system.
Comment—A commenter suggested that BSEE revise proposed § 250.842(c) to clarify the type of approval or acknowledgement that the District Manager will issue following submission of the required documents. The commenter also suggested that BSEE revise proposed paragraph (c) by adding a requirement that a separate notification be submitted to the District Manager, as required by § 250.880, at least 72 hours before commencing production safety system testing.
Response—In response to the first comment, paragraph (c) only requires that the operator notify BSEE that the mechanical and electrical systems were installed in accordance with the designs previously approved by the PE; there is no BSEE approval or response required under paragraph (c).
Regarding the second comment, BSEE is not adding a reference to the production system testing notice required by § 250.880(a)(1) to § 250.842(c) as suggested. Section 250.842(c) deals with the certification required to be submitted prior to production, while the production safety system testing notification required by final § 250.880 may and generally will take place after production begins. Referring to the testing notification requirement from § 250.880 in § 250.842 is unnecessary and potentially confusing.
Comment—A commenter asserted that certification of as-built P&ID under proposed paragraph (d) would be more appropriately done by a CVA surveyor than by a registered PE. The commenter also asserted that the proposed rule does not address the issues in the
Response—No changes are necessary. As previously discussed, this rule addresses a number of the recommendations discussed in the
Comment—One commenter asserted that the requirement in proposed § 250.842(d) for certification by an
Response—BSEE does not agree that this comment warrants any changes and is not aware of any specific conflicts between these regulations and any State law. However, if any operator believes there is any potential conflict the operator should notify the District Manager so BSEE can review the situation and respond appropriately on a case-by-case basis. In the event an actual or potential conflict arises, the operator could also seek approval for an alternative process or a departure under §§ 250.141 and 250.142, respectively.
Comment—A commenter recommended that all references to “piping and instrument diagrams” be replaced with references to “process safety flow diagrams.” The same commenter asserted that 60 days is not sufficient to validate the drawings as correct, certify the drawings as correct, and submit the as-built diagrams and the certification to the bureau. The commenter recommended that BSEE revise paragraph (d) to require the operator to provide BSEE with a copy of the as-built P&IDs within 180 days after production begins.
Another commenter stated that it did not understand the need for the rule to state that all approvals are subject to field verification. The commenter asserted that such verification is a standard practice with any inspection and enforcement process. That commenter and another commenter recommended that BSEE revise paragraph (f) to remove the requirement for field verification of all approvals of design and installation features.
Response—No changes are necessary. P&IDs, SAFDs, and SAFE charts are required, as provided in paragraph (a), before BSEE will approve the safety system. After the platform is producing, BSEE requires the operator to submit these documents again to ensure that any minor changes made during the construction phase are captured. The 60-day timeframe in paragraph (e) for submitting the as-built diagrams to BSEE is sufficient for that purpose; since the facility is built before production begins, the operator will have more than the 60 days after production begins to make these corrections and have the drawings certified. BSEE needs these documents for inspection purposes. The original drawings are used during pre-production, while the as-built drawings are necessary for any BSEE inspection conducted after the platform is on-line and to notify the operator if there are any concerns with the as-built diagrams. The P&IDs are a critical element of this final rulemaking and industry standards (such as API RP 14C, API RP 14J, and API RP 14F) and are separate and distinct from SAFDs.
In addition, removing the sentence pertaining to field verifications from paragraph (f), as suggested by the commenters, would serve no useful purpose, since the regulation also provides that those documents must be made available to BSEE upon request and since, as with all similar documents, the P&IDs and SAFDs are subject to field verification by BSEE during the inspection process.
Comment—A commenter asserted that paragraphs (d) and (e) might conflict with some State requirements under which construction issued documents are sealed while as-built documents are not. The commenter also stated that State requirements also require that the “sealing engineer” be the responsible engineer in charge of the design phase.
Response—No changes are necessary. BSEE does not regulate how operators create the diagrams. As previously explained, BSEE needs to ensure that the diagrams are properly reviewed by qualified PEs and that they meet the standards incorporated in this section. This regulation does not require PEs to be involved in anything that they are not already authorized to do. In the event an actual or potential conflict between this rule and any applicable State law arises, however, the operator should contact the District Manager for guidance. The operator may also seek approval for an alternate process or a departure under §§ 250.141 and 250.142, respectively, on a case-by-case basis.
Comment—A commenter asserted that proposed paragraph (e) of this section would create a new requirement (to submit as-built P&IDs and SAFDs to BSEE within 60 days after production commences) and that the commenter did not understand the purpose of that requirement. The commenter noted that BSEE will have the original design diagrams as part of the application process, and that BSEE will also receive a certification that the installation was done in accordance with the approved diagrams. The commenter asserted that this requirement creates an undue paperwork burden on both the company and the bureau and added that BSEE had severely underestimated the costs for maintaining the “as-built” drawings for the life of the facility (as required by paragraph (f)). The commenter recommended that this requirement be deleted.
Response—BSEE disagrees with these comments. As previously explained, BSEE must have up to date as-built diagrams, which accurately reflect the actual systems in place, for review and inspection purposes, including providing notification to the operator of any BSEE concerns about differences between the original approved diagrams and the as-built diagrams. Modifications are often made to systems during construction or during initial operations, potentially rendering the approved drawings that accompanied the application obsolete. If no changes are made to the system after approval, however, an operator should be able to submit the same drawings that were originally stamped by the PE at little or no extra cost. BSEE's estimates for determining the costs and burdens related to as-built diagrams were based upon BSEE's best professional judgment.
Comment—A commenter noted that proposed paragraph (f) requires that as-built P&IDs be maintained for the life of the facility. The commenter asserted, however, that the proposed rule did not specify whether paragraph (f) applies only to facilities installed/approved after publication of the final rule or whether it also applies to existing facilities. The commenter suggested that the rule and the related information collection approval should clearly state that paragraph (f) applies only to facilities installed and approved after publication of the final rule. The commenter asserted that the costs and information collection burdens would
Response—No changes are necessary. The requirement for as-built diagrams will apply to all production facilities installed or modified after the effective date of the final rule. All safety system submittals made after the effective date of the final rule must comply with the requirements of final paragraphs (a) through (e). All production safety system design and installation documents approved under this section will need to be maintained and readily available as required by paragraph (f).
BSEE also revised final paragraph (b), based on comments received, to clarify the requirements for the establishment of new operating pressure ranges. This includes clarifying that the operator must establish the new operating pressure range after the system pressure has stabilized, and that pressure recording devices must document the pressure range over time intervals that are no less than 4 hours and no longer than 30 days.
Paragraph (c) was revised to include clarification that initial set points for pressure shut-in sensors must be set utilizing gauge readings and engineering design.
Comment—One commenter asserted that the regulations should be revised to state that these sections are not applicable to the design or operation of tanks inside the hull of a floating facility, as USCG requirements for tanks inside the hull of a unit may differ from BSEE requirements. Alternatively, the commenter suggested that the MOA should be revised to give USCG jurisdiction over the design of tanks that are integral to the hull and to give BSEE jurisdiction over non-integral tanks in the hull and over the operation of both integral and non-integral tanks in the hull of the unit that are for produced hydrocarbons, fuel and flow assurance fluids.
Response—The commenter is referring to tanks in the hull of a floating facility. BSEE agrees that the USCG has jurisdiction over the design and operation of tanks in the hull. However, under MOA OCS-04, BSEE has responsibility for regulation of the level safety systems on all product storage tanks, including those in the hull of a floating facility. These tanks are upstream of the production meters. BSEE does not regulate the tank design or how the operator loads the product. However, BSEE needs to ensure there is a safety system in place to ensure the tanks do not overflow. To clarify this issue, BSEE revised paragraph (a) in the final rule by deleting the proposed requirements for tanks with operating pressures less than 15 psig and by adding a specific reference to pressure vessels and fired vessels that are used to support production operations. Further discussion of BSEE's jurisdiction is found in part IV.B.2 of this document.
Comment—One commenter noted that USCG has its own regulations regarding pressure vessels utilized in emergency and ship service systems for floating platforms. The commenter suggested that, for floating facilities, BSEE should state that the proposed regulations do not apply to pressure vessels, waste heat recovery, water heaters, piping or machinery that are associated with the unit's emergency and ship-service systems.
Response—As previously stated, this final rule applies only to operations that are under BSEE authority. Nonetheless, BSEE has revised final paragraph (a) to better delineate the scope of these provisions in relation to BSEE's authority.
Pressure Monitoring
Comment—A commenter questioned the need for continual monitoring in order to observe when the real time system pressure changes by 5 percent. The commenter asserted that most platforms are not equipped with a supervisory control and data acquisition/PLC (SCADA/PLC) type real-time monitoring system that could be programed to monitor and alarm a 5 percent change in operating pressure, although pressure safety high (PSH) and pressure safety low (PSL) safety devices constantly monitor pressure variables and are set to properly respond to an automatic detection of an abnormal condition. The commenter asserted that existing BSEE regulations allow the setting of PSHLs at 15 percent above/below the highest/lowest operating ranges in the production process and that installing equipment to monitor for a change of 5 percent would render the PSHLs redundant. The commenter stated that, currently, whenever PSHLs automatically detect abnormal conditions, the operating range at that time is evaluated to learn if a new range needs to be established. The commenter also asserted that the proposed rule did
Response—BSEE does not agree with the suggestion that operators would need to acquire new real-time monitoring capabilities in order to implement the requirements of this provision. Section 250.851(b) does not require continuous real-time monitoring of pressure range; it only requires the use of pressure recording devices to establish new operating pressure ranges when an observed pressure change exceeds the limits specified in the rule. BSEE expects that operators are already using equipment that measures pressure changes in accordance with the existing regulations and industry standards and that is capable of being used under final § 250.851.
This provision does not preclude operators from setting new operating ranges based on a more conservative approach; that is, avoiding potentially unnecessary shut-ins by setting new pressure ranges when normalized system pressure changes by less than 50 psig or 5 percent. In addition, BSEE has clarified the final rule's requirements for resetting the pressure range, by adding language providing that once system pressure has stabilized, the operator must use pressure recording devices to establish the new operating pressure ranges. The final rule also specifies that the time interval for documenting the pressure range must be no shorter than 4 hours and no longer than 30 days. BSEE added the minimum time provision to ensure that the system pressure is stable before setting the operating ranges. In addition, the time period limitations were set, in part, because pressure spikes and/or surges may not be discernible in a range chart if the run time is too long. These revisions should also alleviate the commenter's concern regarding potential nuisance shut-ins.
Comment—A commenter stated that portions of proposed paragraph (a) were inconsistent with ASME's Boiler and Pressure Vessel Code and recommended revising the proposed rule to align with established codes. The commenter recommended specific language for revising proposed paragraphs (a)(1) and (a)(4).
Response—BSEE has revised this section in the final rule, as previously described, and the language the commenter suggested revising is no longer in the regulatory text.
Comment—One commenter stated that, while this proposal attempts to account for the need to stagger relief valve set pressures, it could potentially create an unsafe condition, depending on the meaning of the term “completely redundant relief valve” in the proposed rule. The commenter noted that some equipment can have multiple causes for high pressure, each of which may produce different amounts of vapor that need to be relieved through the relief valve(s), and that it is not uncommon for some equipment to need multiple relief valves to meet various contingencies, while other equipment may only need a single relief valve. The commenter stated that making all the set pressures the same could lead to “relief valve chatter” (
Response—BSEE agrees with the commenter's reasoning for revising the exceptions language in proposed paragraph (a)(3) and has added the language suggested by the commenter as final paragraph (a)(3)(ii). The exceptions include cases where staggered set pressures are required for configurations using multiple relief valves or redundant valves installed and designated for operator use only.
Comment—A commenter asserted that most operators do not monitor the operating ranges to see if pressures fluctuate by 5 percent, since such fluctuations do not typically indicate a change in the maximum operating pressure. The commenter opined that current industry practices for ensuring that pressures are below the maximum operating pressure are sufficient. To implement the proposed new requirement, the commenter asserted, industry would need to institute new field protocols, requiring additional resources, which would provide uncertain value. The commenter recommended revising the proposed provision to require establishment of new pressure ranges when the normal system pressure changes by the greater of 15 percent or 5 pounds per square inch (psi).
Response—BSEE revised paragraph (b) of this section to be consistent with similar requirements in other sections of the final rule (
For the same reasons (
Comment—A commenter noted that the proposed rule would require approval from the District Manager for activation limits on pressure vessels that have a PSL sensor set less than 5 psi, although some pressure vessels currently operate below 5 psi. The commenter suggested that BSEE delete this requirement because it would create an unnecessary administrative burden.
Response—BSEE did not make any significant changes to the final rule. Setting the PSL sensor below 5 psig requires approval from the District Manager because, in BSEE's experience, pneumatic-type sensors are generally less accurate when pressure is below 5 psig. While the commenter asserts that the requirement would create an unnecessary administrative burden, the commenter did not provide any further information about this asserted burden. If the commenter was referring to burdens on BSEE's District Managers, BSEE does not agree that any such burden would be unnecessary or unwarranted given BSEE's need to ensure that pressure vessels are operating safely. If the commenter was referring to an administrative burden on operators, the commenter did not provide any estimate of that burden.
Comment—A commenter asserted, as an example, that under the proposed regulations, a flowline that has a normalized operating range of 50 psig would have a PSH setting of 57 psig and a PSL setting of 43 psig. The commenter then explained that if the operating range normally changes to 40 psig, due to a naturally depleting well, the PSL will actuate and shut-in the well unnecessarily. The commenter also asserted that the operator would not be able to establish a new pressure range since the change was not “50 psig or 5 percent, whichever is higher.” Therefore, the well would remain shut-in until the range changed by the greater of 50 psig or 5 percent. Thus, the commenter concluded that the proposed regulation would not provide for normalized operating ranges that are below 1,000 psig (since 5 percent of 1,000 psig is 50 psig). The commenter also asserted that BSEE currently permits operators to establish new operating ranges at less than the proposed change requirements of 50 psig or 5 percent, whichever is greater,” to help prevent nuisance shut-ins.
Response—As discussed in regard to similar comments on proposed § 250.851, operators may use a more conservative approach to help prevent nuisance shut-ins, by using a lower change in pressure than that specified in this section (
Comment—A commenter asserted that the proposed language conflicts with the current language in subpart J, and also with the recommended guidance in API RP 14C. The commenter recommended deleting the requirement for the PSV when the shut-in tubing pressure is greater than 1.5 times the maximum allowable working pressure (MAWP) of the pipeline or flowline. The commenter stated that, currently, with the two SSVs with independent PSHs, a safety integrity level (SIL) of 2 is achieved when both SSVs are required to hold bubble tight (zero leakage). The second SSV serves as an alternate safety device to prevent over pressurization of the pipeline.
Response—No changes are necessary, since this section covers only the safety systems on the pipeline, which are part of the production safety system. BSEE regulations do not address or rely on the SIL approach. Although BSEE does not agree that there is a conflict between API RP 14C, as referenced in this section of the final rule, and subpart J, if there is any conflict between any industry standard and any regulation in subparts H or J, operators must follow the regulations. In addition, if there is any conflict between the requirements of subparts J and H, operator must follow the more rigorous requirement, which generally will found in subpart H. . Although BSEE is not aware of a conflict between these final subpart H requirements, API 14C, and subpart J, BSEE will continue to monitor the implementation of both sets of requirements to ensure there are no conflicts. Further, if an operator believes there may be a conflict in a particular situation, the operator may contact the District Manager for advice.
Comment—A commenter suggested revising the section title of proposed § 250.852 so that the section applies only to dry trees on floating facilities
Response—BSEE disagrees with the suggestions for revising the section title and for limiting this section to surface trees and dry well jumper flowlines. The requirements in this section apply to all dry trees, except for paragraph (e), which applies to dry trees on floating facilities, and paragraph (g), which applies to pipeline risers on floating production facilities. The requirements for other safety devices that are used for subsea installations are addressed in §§ 250.873 through 250.875 of the final rule. Thus, BSEE does not agree that the organization of the sections in the final rule is likely to cause any confusion as to requirements for dry trees and subsea installations.
Comment—A commenter suggested revising the language of proposed § 250.852(a)(2), since slugging and other dynamic phenomenon that may be associated with normal flow can often cause the pressure to fluctuate by 5 percent or more. The commenter noted that normalized operating pressure may include variations that are associated with transient or dynamic conditions, such as gas surge from multi-phase slugging during normal operations. The commenter requested clarification as to the requirement to reestablish an operating pressure range when normalized operating pressure changes by 5 percent. The commenter also recommended modifying § 250.852(a)(2) to require pressure recording devices to be used to establish new operating pressure ranges for required flowline or header PSH/PSL sensors at any time the normalized operating pressure changes are outside the parameters of § 250.852(b)(1).
Response—As previously discussed, BSEE has determined that the 5 percent (or 50 psig, whichever is greater) threshold is appropriate because it will both help prevent nuisance shut-ins (through more frequent resetting of operating pressure ranges) and provide earlier warning of potentially dangerous conditions that may require action to prevent a safety or environmental incident. In addition, the 5 percent threshold is consistent with the 5 percent level pressure tolerance levels for PSHL sensors under API RP 14C. (However, if any operator believes that its operating pressures may change by more that 5 percent under normal flow conditions, and that it should use a different threshold for establishing a new pressure range, it may request approval for use of an alternate procedure under existing § 250.141.) As requested by the commenter, however, BSEE has clarified the revised final paragraph (a)(2) to provide additional clarity regarding the use of pressure recording devices to establish new operating pressure ranges.
Comment—A commenter suggested revising the language of proposed § 250.852(c)(1) to allow for a relief valve which vents into the platform flare scrubber or some other location approved by the District Manager that is designed to handle, without liquid-hydrocarbon carry-over to the flare, the maximum anticipated flow of hydrocarbons that may be relieved to the vessel.
Response—BSEE agrees with this comment and has revised the final regulation, by removing the word “liquid” to ensure the flare scrubber is designed to handle the maximum anticipated flow of all hydrocarbons.
Comment—A commenter suggested revising the language in proposed § 250.852(e)(1) to allow designs to be verified through qualification tests since flexible design methodology is proprietary and the manufacturers will not release the design methodology to an independent verification agent (IVA).
Response—The suggested changes are not necessary. The design methodology is contained in API Spec. 17J, Specification for Unbonded Flexible Pipe, which has already been incorporated in existing § 250.803 for flowlines on floating platforms, and which is nearly identical to the requirements contained in final § 250.852(e)(1). The existing regulation, like this final rule, specifies the type of manufacturer documentation, such as design reports and IVA certificates, that operators must review. BSEE is not aware that the concern raised by the commenter has been a significant issue under the existing regulations.
Comment—A commenter requested clarification on this section, asserting that the proposed requirements in paragraphs (g) and (h) were somewhat unclear since they first refer to a “single pipeline riser” on the platform and then refer to “each riser” on the platform.
Response—No changes are necessary. Both paragraphs (g) and (h) address situations involving multiple subsea sources (wells or pipelines) that tie into a single pipeline riser or multiple risers on a platform. If a single flow safety valve (FSV) on the platform to protect multiple subsea pipelines or wells that tie into a single pipeline riser, each riser may have its own FSV (as provided by paragraph (g)) and its own PSHL (as provided by paragraph (h)).
Comment—A commenter asserted that the proposed requirement, in paragraph (d), that level sensors be located on an external bridle (rather than directly on the vessel) is unnecessary, as long as a means of testing the sensor without a level bridle is available. The commenter stated that fouling or foaming services may cause external bridle sensors to misread levels in some services. The commenter added that certain sensor testing technologies (
Response—BSEE disagrees with the commenter. Sensor testing equipment built according to API standards, which are incorporated by reference into BSEE's regulations, should be able to meet this provision. Moreover, an operator that wants to use alternate technology that is incompatible with bridles can propose alternate approaches through the DWOP process
This new section will also require floating production units with swivel stack arrangements to be equipped with a leak detection system for the portion of the swivel stack containing hydrocarbons. The leak detection system will be required to be tied into the production process surface safety system allowing for automatic shut-in of the system.
Comment—A commenter acknowledged that leak detection requirements for floating productions units are an improvement, but asserted that BSEE should prohibit the use of floating production units for long-term production in the Arctic OCS.
Response—BSEE disagrees with prohibiting the use of floating production units for long-term production in the Arctic as this would prematurely, and potentially unnecessarily, limit long-term options for development in the Arctic. Moreover, an operator must demonstrate that any proposed production unit is suitable for its operating environment. Under final § 250.800(a), all oil and gas production safety equipment must be designed, installed, used, maintained, and tested to ensure the safety and protection of the human, marine, and coastal environments. Final § 250.800(a) also requires that, for production safety systems operated in subfreezing climates, the operator must account for floating ice, icing, and other extreme environmental conditions that may occur. In addition, as previously discussed, BSEE may address Arctic-specific issues in future rulemakings, guidance or other documents.
Comment—A commenter stated that the mooring is designed to retain a vessel on location and protect the risers, which should be flushed and/or purged prior to disconnect during a planned process. The commenter then asserted that the proposed requirements in this section could reduce the safety of that system.
Response—BSEE does not agree with the suggestion that the requirements in this section could make the disconnect system less safe. However, BSEE recognizes that, for each floating production system with disconnectable turrets and a turret-mounted system, the system configuration and disconnect process will be unique. BSEE also understands that there are distinctions between an emergency disconnect and a planned disconnect, and that there are personnel safety concerns during any disconnect that the operator must address. Accordingly, BSEE will continue to evaluate the disconnect process on a case-by-case basis as part of the initial planning and review of a facility's plans and systems under a DWOP. In addition, as a condition of approval in the DWOP, BSEE may require the operator to demonstrate the disconnect system once per year.
Comment—A commenter suggested revising the language of proposed § 250.854(b), asserting that, on many swivel stacks with leak detection systems, the rate of a hydrocarbon leak, not the detection of a hydrocarbon leak, is the criterion for an automatic shut-in.
Response—BSEE does not agree that the commenter's recommended changes are necessary. While BSEE agrees that the use of some type of system to detect and contain a leak is appropriate, a catastrophic failure must initiate a process system shut-in. However, a seal failure that causes a leak into the production system, which is contained, will not require an automatic shut-in. This provision protects against a scenario in which those internal seals have failed in such a way that a leak external to the production system (
Comment—A commenter stated the proposed rule references only pneumatic-type valves, while current technology incorporates electronic switching devices. The commenter asserted that an ESD device on a boat landing can be either a breakable loop for pneumatic systems or a stiffen ring on an electronic switch that can be actuated using a boat hook.
Response—BSEE agrees with the commenter's observation that the proposed rule was limited to pneumatic-type valves and did not address the boat landing ESD. In the final rule, BSEE has revised this section to better reflect relevant language in the incorporated API RP 14C (section C.1) and to require that the ESD stations be uniquely identified. Because it is critical that the ESD stations be clearly recognizable and functional during an emergency, BSEE wants to emphasize this requirement.
Comment—A commenter stated that diesel engines usually have an overspeed device that will shut down the run-away engines except when a firewater pump and emergency generator is started due to an emergency shutdown or confined entry air supply. The commenter then asked whether this section would require use of a mechanical air intake device in addition to the overspeed sensor.
Response—Overspeed sensors are always required,. In addition, under final § 250.856, the operator must equip diesel engine air intakes with a device to shutdown the engine in the event of a runaway (
Comment—A commenter recommended that paragraph (b) of this section be limited to fixed platforms only. According to the commenter, under item 12 of MOA OCS-04 between the Minerals Management Service (MMS) (now BSEE) and the USCG, firefighting safety equipment and systems on floating offshore facilities are under the responsibility of the USCG, as are requirements for emergency power sources on floating offshore facilities.
Response—As previously explained, these regulations only apply to operations that are under BSEE authority. In addition, paragraph (b) is essentially a recodification of longstanding BSEE regulations, under which the commenter's jurisdictional questions have not proven to be an issue.
Comment—One commenter noted that the proposed regulations require the installation of a pressure relief valve on the glycol regenerator (reboiler) to prevent over-pressurization, and require that valve to be vented in a non-hazardous manner. The commenter suggested that the regulation should provide specific instructions on how the operator can vent the glycol regenerator in a non-hazardous manner. The commenter also noted that BSEE requested additional comments on opportunities to limit emissions from OCS production equipment. The commenter recommended that BSEE require emission control systems to be installed on OCS glycol dehydration units or require the use of desiccant dehydrators (where technically feasible). The commenter also recommended that the regulations be revised to require OCS operators to install flash tank separators, optimize the glycol circulation rate, and reroute the skimmer gas.
Response—The provision of the final rule requiring that the relief valve discharge must be vented in a non-hazardous manner is a recodification of longstanding BSEE regulations. The commenter is asking instead for a prescriptive requirement on how the operator should vent the glycol regenerator in a non-hazardous manner. There are many ways this can be accomplished. The commenter itself described three different approaches to achieving this. However, BSEE does not want to limit the options to just a few approaches; rather, the final rule sets a performance goal and allows the operator to decide the best approach to achieve the required goal. This performance-based approach, involving the same standards, has worked under the existing regulation.
BSEE appreciates the commenter's recommendations regarding emissions controls and will consider them. BSEE may also consider additional measures, such as emission control systems, in the future to ensure safety and protect the environment; however, those measures are outside the scope of this rulemaking.
Comment—One commenter stated that the proposed rule listed some, although not all, safety devices for equipment specified in API RP 14C, which allows operators to rebut the need for some safety devices according to safety analysis checklists The commenter asserted that the requirements in this proposed regulation may restrict that option. The commenter suggested deleting these requirements and referencing the requirements in API RP 14C, as in proposed § 250.865(a). The commenter also suggested that the requirement in proposed § 250.857(c) regarding installation of the SDV should be required only for new designs or modifications to glycol dehydration units.
Response—No changes to the final rule are necessary. Requiring two valves on the glycol dehydration units, as proposed, helps ensure safety of the operations. The requirements of this section are in addition to API RP 14C, which requires a shutdown valve, but
After consideration of various issues raised by commenters, BSEE omitted proposed paragraph (c), which would have provided an exception to the installation of PSHs and PSLs for vapor recovery units (VRUs) when the system is capable of being vented to the atmosphere, from the final rule.
BSEE added a new paragraph (c) to the final rule that includes the contents of proposed paragraphs (b)(1) through (b)(3). New paragraph (c) also clarifies that initial set points for pressure sensors must be set utilizing gauge readings and engineering design. These changes were made to make the requirements for operating pressure ranges and pressure sensors consistent with similar provisions in other sections of the final rule.
Comment—A commenter suggested revising the language in proposed § 250.858(a)(3) to allow temporary flaring of gas-well gas in the event of an upset condition within allowable flare limits. The commenter suggested that gas-well gas affected by the compressor's closure of the automatic SDV could be shut-in manually or temporarily diverted to a flare if compliant with §§ 250.1160 through 250.1161.
Response—As the commenter noted, temporary flaring of gas-well gas is directly addressed in part 250, subpart K (§§ 250.1160 and 250.1161), which sets the conditions for flaring or venting gas-well gas. However, after consideration of issues related to this comment, BSEE agrees with the commenter that allowing gas-well gas to be flared or vented in the event of an upset condition with a gas compressor can be done consistently with existing §§ 250.1160 and 250.1161. Accordingly, BSEE has changed the language in final § 250.858(a)(3) to clarify that gas-well gas can be diverted to flare or vent in accordance with the requirements §§ 250.1160 and 250.1161.
However, BSEE has deleted proposed paragraph (c), which would have created a general exception to the installation of PSHs and PSLs for VRUs when the system is capable of being vented to the atmosphere. BSEE deleted that proposed exception because, after considering all the issues raised by commenters, BSEE realized that, for some VRUs, the volume of gas from the tank could create a suction pressure exceeding 5 psig, resulting in an over-pressure that could cause the VRU to burst. Therefore, BSEE decided that it needs to confirm that the system is operating at 5 psig before approving a system that could be vented to the atmosphere without a PSH and PSL installed.
Comment—A commenter noted that the proposed regulation did not compensate for lower operating ranges throughout the compressor skid, especially when considering VRUs. The commenter noted that it is highly unlikely that a VRU would have an operating change of 50 psig or greater and expressed concern that the proposed requirement for compressor discharge sensors did not provide for normalized operating ranges. The commenter questioned the purpose of the proposed rule, since the commenter asserted that operators are currently permitted by BSEE to establish new operating ranges at less than the proposed pressure change threshold of 50 psig or 5 percent, whichever is greater, to help prevent nuisance shut-ins.
Response—BSEE disagrees with the suggestion that this regulation will not help prevent nuisance shut-ins. As previously discussed in response to similar comments, establishing new normalized operating pressure ranges, whenever actual operating pressure changes by the amounts specified in this provision, will help prevent nuisance shut-ins. Operating pressure ranges need to be re-established periodically, and sensors need to be reset to reflect normal changes in operating pressures. If not, shut-ins are more likely to occur because the unadjusted pressure range and sensors could indicate an abnormal condition when a pressure change would otherwise be considered routine and within the adjusted pressure range. In addition, as previously explained, BSEE has set the threshold for requiring the establishment of new pressure ranges at levels that provide a reasonable safety cushion. However, BSEE agrees with the commenter in that an operator may choose to set a pressure change threshold below 50 psig or 5 percent in order to re-set the normalized operating pressure range more frequently (and thus further reduce the possibility of a nuisance shut-in) than would otherwise be required under this regulation.
Comment—A commenter noted that the proposed section used language suggesting that it would apply to devices on reciprocating compressors and recommended that BSEE include an additional section for centrifugal compressors since they appear to comply with API RP 14C as well.
Response—BSEE revised this section to better conform to the language of API RP 14C which does not distinguish between the different types (
Final § 250.859(a) clarifies the requirements for firefighting systems on fixed facilities only, and includes requirements from existing § 250.803(b)(8)(i) and (ii), as proposed. Final paragraph (a) also requires, as proposed, that within 1 year after publication of the final rule, operators must equip all new firewater pump drivers with capabilities for automatic starting upon activation of the ESD, fusible loop, or other fire detection systems. Final paragraph (a) also requires that, for electric-driven firewater pump drivers, operators must install an automatic transfer switch to cross over to an emergency power source in order to maintain at least 30 minutes of run time in the event of a loss of primary power. The final rule also specifies requirements for routing power cables, or conduits with wires installed, between the fire water pump drivers and the automatic transfer switch away from hazardous-classified locations that can cause flame impingement.
Final paragraphs (a)(3) and (4) include the requirements of former § 250.803(b)(8)(iv) and (v) regarding firefighting system diagrams and subfreezing climate suitability, respectively. Final paragraph (a)(5) requires operators to obtain approval from the District Manager before installing any firefighting system. Final paragraph (a)(6) requires that all firefighting equipment located on a facility be in good working order.
Final paragraph (b) was added to clarify the requirements for firewater systems to protect all areas where production-handling equipment is located on floating facilities. This section also requires the operator to install a fixed water spray system in enclosed well-bay areas where hydrocarbon vapors may accumulate and provides that the firewater system must conform to applicable USCG requirements.
Final paragraph (c) specifies that if an operator is required to maintain a firewater system which becomes inoperable, the operator either must shut-in its production operations while making the necessary repairs or, for fixed facilities, request that the appropriate District Manager grant a departure under § 250.142 to use a firefighting system using chemicals on a temporary basis for a period up to 7 days while the necessary repairs to the firewater system are made. This paragraph also clarifies that, for fixed facilities, if the operator is unable to complete repairs during the approved time period because of circumstances beyond its control, the District Manager may grant extensions to the approved departure for periods up to 7 days.
Comment—A commenter noted that firefighting systems have redundancy and that they can be fully functional, and redundant, even when some equipment is down for repair. The commenter asserted that this rule should make provisions for this to avoid a facility being deemed out of compliance when some components of the firewater system are being repaired, even though the system as a whole is still functional.
Response—BSEE disagrees. To safely conduct operations the firefighting systems must be fully functional. Redundancy is required in case the system fails when needed, not to provide coverage for repairs.
Comment—A commenter asserted that, for both fixed and floating facilities, USCG has jurisdiction over most of the fire protection, detection, and extinguishing system areas, except for the production handling area. The commenter suggested that the regulations should be limited to this area only, and that any proposed requirements for firefighting in other areas, including well bays, should be removed, along with requirements for fire water pumps. The commenter also requested that all discussion of firewater systems, chemical firefighting systems, and foam systems should be clarified to state that they apply only to the production-handling area. The commenter asserted that USCG has jurisdiction for fire and smoke detection, so those requirements should be limited to interfaces with BSEE systems (such as the ESD system).
Response—This comment was also made in reference to §§ 250.842 and 250.861. As discussed in response to other comments, BSEE's regulations apply only to operations and systems that are under BSEE's authority. (
To further clarify this point, BSEE has revised paragraph (a) in the final rule so that the requirements expressly apply to areas where production-handling equipment is located on fixed facilities. BSEE also revised final paragraph (b) to clarify that the requirements in that paragraph apply to areas on floating facilities where production-handling equipment is located. In addition, final paragraph (b) requires the firewater system to conform to USCG requirements for firefighting systems on floating facilities. Further, BSEE revised final paragraph (c) to clarify that the provision allowing an operator to request permission from BSEE to temporarily use a chemical firefighting system, in the event the firewater system becomes inoperable, applies to fixed facilities only. In addition, as discussed in part IV.C, BSEE has revised the firefighting-related requirements of final §§ 250.859 through 250.862 to further clarify that they apply to areas and systems under BSEE's authority, and to confirm that operators must also comply with applicable USCG regulations. Section 250.842 already clearly states that it applies to the production safety system.
Comment—A commenter suggested that BSEE work with Arctic firefighting experts to develop firefighting system regulations to address suppression of hazardous material, electrical, flammable liquid, and combustible liquid fires that may occur at Arctic OCS operations and that BSEE should include those requirements in the regulation. The commenter noted that BSEE proposed a number of improvements to firefighting systems for OCS operations, including a proposed improvement at § 250.859 that requires OCS facilities to be shut-in if the firewater system becomes inoperable. However, the commenter asserted that the regulations do not appear to address specific firefighting requirements
Response—BSEE understands that the Arctic may present unique operating conditions. Final § 250.859(a)(4) includes firewater system requirements for operations in subfreezing climates, including a requirement to submit evidence demonstrating that the firefighting system is suitable for subfreezing conditions. Any permit application must address the specific operating conditions where the activity is taking place, and BSEE considers those conditions when reviewing a permit application. Any firefighting system proposed for use in the Arctic OCS, must be able to perform in the environmental conditions found in the Arctic. Specific requirements for chemical firefighting systems are found in § 250.860 of this rulemaking. However, as already explained in response to other comments, BSEE expects to address other Arctic-specific issues in the future through a variety of mechanisms, potentially including separate rulemakings, guidance, or other documents.
Comment—A commenter asserted that BSEE would be correct to require an alternative power source for firefighting systems because, if the main engine room, the main engines, or associated power cables are disrupted by fire, the firefighting systems may become inoperable. The commenter asserted that an alternative power source, preferably placed in a location separate from the main engine room should be available to provide alternative power to firefighting equipment during an emergency.
Response—BSEE generally agrees with the comment and has finalized paragraph (a)(2) with only minor wording and organizational changes. BSEE notes that, if an electric firewater pump is based on a fuel gas system, the personnel on the facility may not have adequate time for egress if they need to shut down the generator. Accordingly, the final rule requires an emergency power source with an automatic transfer switch and requires that fuel or power for firewater pump drivers must be available for at least 30 minutes of run time during a platform shut-in. The operator must also install an alternate fuel or power supply to provide for this pump operating time, if needed. This is consistent with the provisions in the proposed rule.
Comment—A commenter agreed that the inclusion of certain proposed provisions would enhance safety, but asserted that the incremental benefits of incorporating all of API RP 14G standard would not justify the increased costs. The commenter stated that API RP 14G does not offer a “cookbook” method of designing and installing a complete firefighting system; instead, API RP 14G offers recommended criteria for whatever firefighting system the operator chooses to install. The commenter asserted that the proposed rule did not account for existing systems that were approved under the current regulations and under current approval and inspection policies. The commenter also asserted that the proposed rule did not take into account potential conflicts with USCG firefighting requirements for floating facilities.
The commenter recommended that BSEE separate firefighting requirements for fixed facilities from those for floating facilities since the latter are driven mainly by the USCG. The commenter also recommended revisions to clarify the separate requirements for fixed facilities and floating facilities and to account for currently approved systems in service.
Response—BSEE agrees with several of the commenter's recommended changes and has revised this section accordingly. BSEE also revised final paragraph (a) to state that the “firewater system” on fixed facilities must conform to API RP 14G, in order to clarify that compliance with API RP 14G is required only for the firewater systems and not for all firefighting systems, as implied by the proposed language. (This revision is also consistent with the existing regulations.)
As suggested by the commenter, BSEE also revised the final rule to clarify the separate requirements for firefighting systems on fixed facilities and floating facilities. These changes help ensure that there are no conflicts with the USCG for firefighting systems by focusing this final section on areas where production-handling equipment is located and on enclosed well-bay areas where hydrocarbon vapors may accumulate, and by referring to the need to comply with USCG requirements for floating facilities.
Final § 250.860(a) addresses the potential use of a chemical-only firefighting system, in lieu of a water-based system, on any fixed platform that is both minor and unmanned. Final paragraph (a) authorizes the use on such platforms of either of two types of portable dry chemical units, as long as the operator ensures that the unit is available on the platform when personnel are on board. A facility-specific authorization from BSEE would not be required under this paragraph.
Paragraph (b) of the final rule allows use of a chemical firefighting system, in lieu of a water-based system, on any fixed major platform or minor manned platform, if the District Manager determines that the use of a chemical-only system provides equivalent fire-protection control and would not increase the risk to human safety. To provide a basis for the District Manager's determination that the use of a chemical system provides equivalent fire-protection control, final paragraph (c) requires an operator to submit a justification addressing the elements of fire prevention, fire protection, fire control, and firefighting on the platform. Final paragraph (c) also requires the operator to submit a risk assessment demonstrating that a chemical-only system would not increase the risk to human safety. That paragraph lists the items that the operator must include in the risk assessment.
Final § 250.860(d) addresses the documentation that an operator must maintain or submit for the chemical firefighting system. This paragraph also clarifies that, after the District Manager approves the use of a chemical-only fire suppressant system, if the operator intends to make any significant change to the platform (such as placing a storage vessel with a capacity of 100
Comment—A commenter recommended that this paragraph be limited to fixed platforms only because, in accordance with item 12 of the MOA OCS-04 between MMS (now BSEE) and the USCG, firefighting safety equipment and systems on floating offshore facilities are the responsibility of the USCG.
Response—As already explained in response to other comments, BSEE's regulations only apply to operations that are under BSEE authority. However, BSEE has added language to the beginning of this section in the final rule to clarify that it applies to fixed platforms only. (
Comment—A commenter asserted that BSEE was proposing to codify existing NTL No. 2006-G04, but that the proposed rule did not indicate how the proposed risk assessment criteria will be evaluated. The commenter understands that BSEE developed a risk matrix for use in evaluating an operator's risk assessment. The commenter recommended that BSEE include the risk matrix with the risk assessment criteria in the final rule in order to save both the operator and BSEE time in preparing and reviewing, the request.
Response—No changes are necessary. The final rule includes the categories of information required for BSEE's risk assessment from NTL No. 2006-G04, “Fire Prevention and Control Systems.” The operator must address those categories; however, BSEE does not believe it is necessary or appropriate to include the requested details in this final rule. Such details may be better addressed in an internal BSEE guidance document, which may be revised as circumstances warrant.
Comment—A commenter recommended that this paragraph be limited to fixed platforms only. The commenter asserted that item 12 of the MOA OCS-04 between MMS (now BSEE) and the USCG provides that firefighting safety equipment and systems on floating offshore facilities are the responsibility of the USCG.
Response—BSEE does not agree that the recommended change is necessary. As previously explained, these regulations apply only to those operations, whether on fixed or floating platforms, that are covered by BSEE authority. However, BSEE has revised the final rule to clarify that it applies only to production handling areas, which are subject to BSEE's authority.
Comment—A commenter stated that proposed paragraphs (a) and (b) would impose new requirements for sending in samples for testing. The commenter asserted that this would require additional costs and resources to comply but would not add significant value. The commenter also stated that other requirements in paragraph (a) would be sufficient to ensure the suitability of the foam.
Response—BSEE does not agree that the testing requirements of this section will not add value. Regular testing of the foam concentrate will ensure that it does not deteriorate and that it will be effective in the event of a fire. If an operator plans for sampling and testing in accordance with this section, that process should not add significant new costs. For example, the sampling can be arranged to coincide with already scheduled trips to and from the facility.
Comment—A commenter recommended that this paragraph be limited to BSEE regulated safety systems only. The commenter asserted that item 12 of the MOA OCS-04 between MMS (now BSEE) and the USCG provides that fire and smoke detection systems on floating offshore facilities are responsibility of the USCG, except where those detection systems interface with BSEE regulated safety systems.
Response—As previously discussed, these regulations apply only to operations that are under BSEE's authority. Proposed § 250.862, in effect, merely proposed to recodify, with
Comment—A commenter suggested revising the requirement for “gas detection systems” in proposed § 250.862(e) to “gas detectors,” asserting that there is “type approval” in place for gas detectors but not for gas detection systems. The commenter also stated that some legacy gas detectors do not have approval because they were manufactured prior to the approval standard issue date, and recommended that BSEE apply the proposed requirement only to new installations. The commenter also asserted that the proposed rule could conflict with USCG requirements for fire and gas detection systems on floating offshore installations.
Response—The relevant provisions in the final rule are consistent with current regulations. The distinction identified by the commenter between “gas detection systems” and “gas detectors” does not present an issue under these longstanding requirements; nor should the recodification of the existing requirements apply only to new installations. In addition, as previously discussed, these regulations apply only to operations that are under BSEE's authority. Nonetheless, BSEE has revised the final rule to clarify that it applies only to production processing areas and that, in the event compliance with any provision of the standards would be in conflict with any applicable USCG regulation, compliance with the USCG regulation controls.
Comment—A commenter recommended that this paragraph be limited to BSEE-regulated electrical systems only. The commenter asserted that item 14 of the MOA OCS-04 between MMS (now BSEE) and the USCG provides that electrical systems—other than production, drilling, completion well servicing and workover operations—on floating offshore facilities are the shared responsibility of BSEE and the USCG, except for emergency lighting, power generation and distribution systems, which the commenter stated are the sole responsibility of the USCG.
Response—Final § 250.863, in effect, merely recodifies the longstanding requirements of existing § 250.803(b)(10), which was in effect at the time the MOA referred to by the commenter was developed and the application of which has not presented jurisdictional issues. This final rule is not a substantive change to the existing regulations, and only applies to operations under BSEE's authority. Thus, there is no reason to adopt the commenter's suggested revision.
Comment—A commenter observed that this section would be clearer if it addressed corrosion monitoring and corrosion control as two separate aspects of a corrosion management program. The commenter recommended that BSEE require that operators implement erosion monitoring programs for wells or fields that have a history of (or could reasonably be expected to encounter) erosion due to sand production. The commenter asserted that, with this revision, not all fields/wells/leases would require an erosion control program.
Response—The proposed rule did not propose any substantive changes to the requirements in the existing regulation. By contrast, the commenter's suggested revision would impose new requirements for corrosion monitoring and control and erosion monitoring that were not part of the proposed rulemaking and are outside the scope of this final rule.
BSEE also added new paragraph (c) in the final rule to improve the presentation and clarity of the information contained in proposed paragraph (b), reformatting that information as a table to be consistent with the structure in other sections related to PSLs and PSHs, and to clarify that initial set points for pressure sensors must be set using gauge readings and engineering design. Final paragraph (c) is consistent with the requirements for operating pressure ranges and pressure sensors in other sections of the final rule.
In light of the other revisions made to the proposed section, the remaining paragraphs of the proposed rule were redesignated as paragraphs (d) through
Comment—One commenter declared that a pressure change of 50 psig or 5 percent is too low a threshold to require re-running a pressure chart and suggested raising the pressure change threshold 100 psig or 15 percent.
Response—No changes are necessary. As discussed in response to similar comments on other sections, the proposed—and now final—threshold is consistent with similar requirements in other sections of the final rule, and is intended to both reduce the number of nuisance shut-ins and to provide a safety “cushion” that will give operators more time to act in the event the pressure change indicates an actual abnormal condition. The commenter's suggestion for a higher threshold, by contrast, would not accomplish those goals, as previously discussed, and could result in higher risk that an incident will occur.
Comment—One commenter noted that it was unclear as to what “pumps” the requirement in proposed paragraph (a) would apply. The commenter assumed that this provision would apply only to those pumps in the production process and to pipeline transfer, small volume produced hydrocarbon transfer, or other process fluids transfer pumps recognized in API RP 14C. The commenter recommended that BSEE clarify this requirement to apply only to those pumps specifically recognized in API RP 14C.
Response—No changes are necessary. This section, by its terms, is applicable to the types of surface pumps specified in the section heading and addressed by API RP 14C, which is already incorporated in longstanding BSEE regulations. BSEE is not requiring operators to follow API RP 14C for any surface pumps other than those specified in that standard.
Comment—A commenter claimed that continuous monitoring for a 5 percent pressure change threshold would be problematic and asserted that the proposed regulation would not compensate for lower operating ranges, especially when considering pumps that discharge to pressure vessels that operate at just above atmospheric service. The commenter included an example scenario for a sump pump discharging to a pressure vessel, and discussed the effects the proposed requirement would have under that scenario.
Response—No changes are necessary. As previously stated, the 5 percent pressure change threshold is consistent with the API RP 14C pressure tolerance setting for PSHL sensors. Moreover, the thresholds established by the rule represent pressure changes at which an operator must establish new operating pressure ranges; however, operators may use a more conservative approach, by resetting their operating pressure ranges following a pressure change that is less than 5 percent or 50 psig, to account for situations like that raised by the commenter. If there are additional concerns about the operating range in a specific situation, operators may contact the District Manager for guidance. BSEE also added language to final paragraph (b) to clarify the requirements for establishing the new pressure range.
Comment—According to a commenter, most operators do not monitor the operating ranges to see if they fluctuate by 5 percent because such fluctuations do not typically indicate a change in the maximum operating pressure. The commenter stated that current practices for ensuring pressures are below the maximum operating pressure are sufficient to ensure proper operation, that industry would need to institute new field protocols, which would require additional resources by the operator, to comply with the proposed requirement, and that it is not clear that this new requirement would add value beyond current requirements. The commenter recommended specific revisions to paragraph (b) that would increase the proposed 5 percent pressure change threshold to 15 percent.
Response—No changes are necessary. As discussed in prior responses to similar comments, the thresholds in this section of the proposed and final rule are intended to help prevent nuisance shut-ins as well as safety and environmental incidents, while the commenter's suggested higher thresholds would not satisfy the safety and environmental protection goals of this section and would not help prevent nuisance shut-ins through more frequent re-setting of operating pressure ranges. If an operator has additional concerns about the specified threshold for re-setting the operating pressure range under specific circumstances, the operator can contact the District Manager for guidance or seek approval for an alternate procedure under the DWOP process or existing § 250.141. However, BSEE added language to the final rule (consistent with similar provisions in other sections) that specifies a time interval for recording pressure as a basis for a new operating pressure range. This clarification should help mitigate the commenter's asserted concern about the need for new field protocols.
Comment—A commenter suggested revising the language of proposed § 250.865(b), since the highest operating pressure of the discharge line should include the transient pressure spike associated with starting up or shutting down system pumps, provided that the pressure spike is within the system MAWP; otherwise, the commenter asserted, the PSH sensor will trip whenever an additional pump is started, forcing operations to temporarily bypass the PSH sensor. The commenter stated that it is very difficult to completely design away transient pressure spikes for liquid-filled systems. The commenter also requested that BSEE clarify the proposed requirement for re-establishing operating pressure range when normalized operating pressure changes by 5 percent. The commenter also asserted that proposed § 250.865(b) would only prohibit setting PSH/PSL trip points that are more than 15 percent above/below the established pressure range, so that a 5 percent change in pressure that moves the operating pressure closer to the trip point would not violate this requirement. The commenter suggested that, to avoid conflicts, re-running the range charts should only be required if the change exceeds the parameters of § 250.865(b). The commenter also recommended specific revisions to paragraph (b) to address the commenter's concerns.
Response—No changes are necessary. With regard to the commenter's concern about transient pressure spikes (during start-ups or shutdowns) causing the PSH sensor to trip, BSEE revised final paragraph (b) by adding minimum and maximum time periods (
With regard to the commenter's assertions regarding the proposed PSH/PSL trip points (which BSEE moved from paragraph (b) to paragraph (c) in the final rule), BSEE agrees that this provision does not preclude an operator from setting a PSH or PSL trip point below the specified maximum of 15 percent (or 5 psi, whichever is higher) above the highest operating pressure of the discharge line. Thus, as the commenter observed, a trip point that is 5 percent above the highest operating pressure of the discharge line would not violate this requirement. However, BSEE notes that, as proposed, final paragraph (c) specifies that the trip point for a PSH sensor must be set at least 5 percent (or 5 psi, whichever is greater) below the set pressure of the PSV; not 15 percent below the pressure range, which the commenter incorrectly implied was part of the proposal. The 5 percent limit in this provision is intended to improve safety and environmental protection by assuring that the pressure source is shut-in before the PSV activates; while the 15 percent limit suggested by the commenter would not be as effective in meeting those goals. If an operator has any additional concerns about its operating pressure range, it they can contact the District Manager for guidance.
Comment—One commenter noted that, under proposed paragraph (f), the pump maximum discharge pressure must be determined using the maximum possible suction pressure and the maximum power output of the driver. The commenter asserted that the maximum discharge pressure for centrifugal pumps typically is determined by the maximum suction pressure at the shutoff head and, for positive displacement pumps, by the set pressure of the PSV at the discharge.
Response—BSEE agrees with the commenter and has revised final paragraph (g) of this section to clarify the appropriate method to determine the pump maximum discharge pressure, using the maximum possible suction pressure and the maximum power output of the driver as appropriate for the pump type and service.
Comment—A commenter asserted that this proposed requirement is out of place in this section of subpart H, stating that it is a general duty statement that belongs in subpart A at § 250.107. The commenter recommended deleting this requirement from subpart H.
Response—BSEE does not agree that it would be appropriate to move this provision to subpart A at this time. BSEE agrees with the commenter that this requirement might be an appropriate addition to subpart A at a future date through a separate rulemaking. Moving this section to subpart A in this final rule, however, would be outside the scope of this rulemaking. Nor is it inappropriate to include this requirement in subpart H, since it is certainly applicable to personnel safety equipment located on facilities subject to this final rule.
Comment—Several comments requested clarification on BSEE's responsibilities for personnel safety equipment requirements on the OCS compared to USCG's responsibilities. The commenters expressed their opinion that USCG, not BSEE, should have oversight for required and non-required personnel safety equipment on the OCS. They recommended that BSEE remove this requirement from subpart H.
Response—BSEE is not requiring any new additional personnel safety equipment under this provision, but only requiring that this equipment, if located on a facility, be maintained in good working condition. As previously discussed, this final regulation applies to operations and systems, including safety issues, on facilities under BSEE's jurisdiction.
Comment—A commenter asserted that the proposed rule exceeded BSEE's authority as fire-fighting requirements for accommodations and machinery spaces are the responsibility of the USCG. Additionally, the commenter stated that there are no BSEE requirements in either the existing regulations or the proposed regulations that require firewater systems in permanent quarters or temporary quarters. The commenter recommended that BSEE delete this section from the proposed rule.
Response—As previously discussed, these regulations apply only to
In addition, BSEE expects operators to address the impacts of the temporary quarters and temporary equipment in their SEMS plans. This could include, for example, conducting a hazards analysis (
Comment—A commenter suggested that this section should be revised to prohibit non-metallic piping for hydrocarbons. The commenter asserted that firefighting piping can be made out of fiberglass reinforced plastic, provided that it does not penetrate a bulkhead and is always wet inside. The commenter asserted that polyvinyl chloride firefighting piping is not good practice and should never be allowed. The commenter also stated that non-metallic piping should not be allowed to penetrate bulkheads or decks, even if atmospheric. The commenter also suggested that BSEE's rules for non-metallic piping should take into consideration the USCG's rules.
Response—BSEE agrees that the proposed section did not fully address all situations in which use of non-metallic piping would or would not be allowed, and that there could be potential confusion about the proposed rule's relation to USCG regulations. Accordingly, BSEE revised this section in the final rule to require that the use of non-metallic piping on fixed facilities be in accordance with the requirements of § 250.841(b), which specifically addresses platform production process piping and which incorporates API RP 14E, including provisions for non-metallic piping. This revision will provide greater clarity to operators while achieving the original purpose of the proposed rule.
Comment—A commenter recommended that BSEE limit the proposed requirement in accordance with MOA OCS-04 between MMS (now BSEE) and the USCG. The commenter asserted that piping in galleys and living quarters, as well as firewater systems piping, on floating offshore facilities is the responsibility of the USCG. The commenter added that USCG has specific requirements for the use of non-metallic piping in USCG-regulated systems on such facilities.
Response—As stated in prior responses, BSEE's regulations apply only to operations and systems that are under BSEE authority. However, to further clarify this point, BSEE has revised this section to specify that it only applies on fixed OCS facilities, and to refer back to § 250.841(b), which specifically addresses production process piping and which also incorporates API RP 14E's provisions for non-metallic piping. These revisions limit the scope and applicability of final § 250.868 so as to avoid concerns about its consistency with MOA OCS-04 (as updated on January 28, 2016).
Comment—One commenter asserted that the proposed regulatory text is confusing in its use of the term “atmospheric,” in that the examples given in the proposal implied pressurized piping greater than atmospheric pressure. The commenter said that typical freshwater piping in galleys and living quarters operates at ±75 psig and firewater systems piping operates at ±200 psig.
Response—BSEE agrees with the commenter that the piping in galleys and living quarters and firewater system piping is pressurized piping. BSEE has revised this section in the final rule and eliminated the proposed references to piping in galleys and living quarters and in firewater systems, thus eliminating the potential confusion noted by the commenter. Instead, the final rule now refers to the more comprehensive requirements of § 250.841(b).
Comment—A commenter suggested revising the language of proposed § 250.868, since it would cover new technology such as non-metallic HPHT pipe (
Response—As previously stated, BSEE revised this section in the final rule to limit it to fixed OCS facilities and to cross-reference the requirements of final § 250.841(b). Topside WI piping is only found on floating facilities, which are outside the scope of this final provision. The design of subsea jumpers is covered in subpart J of BSEE's regulations and is likewise not within the scope of this section.
In addition, as proposed, final paragraph (a) requires that a designated visual indicator be used to identify a bypassed safety device and establishes required monitoring procedures for bypassed safety systems. Final paragraph (a)(1) also sets forth the monitoring requirements for non-computer-based safety systems, while paragraph (a)(2) sets forth the monitoring requirements for computer-based technology systems. More
In addition, final paragraph (a)(3) specifies that operators must not bypass, for startup, any element of the emergency support system (ESS) or other support system required by Appendix C of API RP 14C without first receiving approval from BSEE for a departure.
Comment—A commenter requested that BSEE revise this section to clarify whether it would require additional pressure and temperature-take points on subsea trees and other subsea equipment. The commenter asserted that it is usually desirable to minimize these leak paths.
Response—No changes are necessary. This regulation does not introduce additional leak paths; it only separates process controls from safety controls in order to ensure the sensing line is only performing a single function. If the process controls and safety controls were not separate, a problem with one system could result in a problem with both systems, thus creating a greater risk that a failure in a process control would also cause a safety system malfunction. Requiring separate systems is also consistent with API RP 14C, which states that the safety system should provide 2 levels of protection, independent of and in addition to the control devices.
The final rule also provides that if an operator does not install time delay circuitry that bypasses activation of PSL sensor shutdown logic for a specified time period on process and product transport equipment during startup and idle operations, the operator must manually bypass (pin out or disengage) the PSL sensor, with a time delay not to exceed 45 seconds.
Comment—One commenter stated that BSEE should not be involved in these day-to-day operational decisions regarding pressure safety devices, as proposed in this section.
Response—Appropriate use of pressure safety devices is critical to ensuring safety and protection of the environment. However, BSEE revised this section in the final rule to state that the operator may apply the class logic, but is not required to use it. This revision gives the operator greater flexibility in meeting this safety goal by allowing for time delays, instead of requiring the operator to bypass the PSL sensors.
Comment—A commenter recommended that PSL sensors should not be required to have timed or pressure build-up bypasses for startup activities. The commenter also asserted that the proposed rule implied that all three industry standard Class logics must be applied simultaneously. Therefore, the commenter recommended that the first sentence be reworded as follows: “You may apply industry standard Class B, Class C, or Class B/C logic to applicable PSL sensors installed on process equipment. . . .” The commenter also asserted that the proposed time limit of 45 seconds for delaying the PSL sensor bypass could be unreasonable during a startup scenario and could cause startup operations to be rushed unnecessarily. The commenter recommended that the time delay be extended to several minutes to account for this.
Response—BSEE agrees with the commenter regarding the proposed class logic language and revised paragraph (a) of this section to state that the operator may apply any or all of the Class B, C or B/C logic, but is not required to use any of those choices. This gives the operator flexibility by allowing for time delays, instead of requiring the operator to bypass the PSL sensors. If BSEE had required the operator to apply class logic, some existing facilities would need to be retrofitted. This revision is consistent with the intent of the proposed rule, which provided in paragraph (b) that an operator that does not use a class logic approach must manually bypass the PSL sensor.
However, BSEE disagrees with the suggestion for extending the time limit on delays to several minutes. Based on BSEE's experience, and consistent with NTLNo. 2009-G36, 45 seconds is typically a reasonable period for pressure to fluctuate before it becomes necessary to alert the operator to an abnormal condition that must be addressed. By contrast, allowing the pressure to remain low for several minutes before the sensor alerts the operator could significantly increase the potential safety risk from the abnormal condition. Thus, BSEE must approve any request to extend the delay period beyond 45 seconds in a specific case.
Comment—The commenter asserted that operators should be required to obtain BSEE approval for any variance from a regulatory requirement, including industry standards incorporated by reference into the regulations, and from any approval, permit, or authorization issued by BSEE for an OCS oil and gas production facility.
Response—These types of requests are already covered by existing §§ 250.141 and 250.142 in the form of alternate compliance and departure requests, respectively; therefore, no revision to the regulation is needed in response to this comment.
Comment—A commenter recommended that BSEE revise this section to state that it is not applicable to the design or operation of tanks inside the hull of a floating facility. The commenter asserted that USCG requirements may be different from BSEE requirements for tanks inside the hull of a unit. Alternatively, the commenter suggested that BSEE-USCG MOA OCS-04 should be revised to give USCG jurisdiction over the design of any tanks that are integral to the hull and to give BSEE jurisdiction over any non-integral tanks in the hull of the unit and over the operation of both integral and non-integral tanks in the hull of the unit that are for produced hydrocarbons, fuel and flow assurance fluids.
Response—BSEE disagrees. This section relates to atmospheric vessels that are a component of drilling, completion, well servicing, and workover operations and that are under BSEE jurisdiction. BSEE is not regulating the design or operation of the tanks; rather, this regulation only requires sensors to ensure safety in the operations BSEE oversees. This is consistent with MOA OCS-04, which was updated in January 2016, and which applies only to floating facilities.
Comment—A commenter asked whether it was BSEE's intent to include non-permanent storage of chemicals and other substances used for ancillary operations such as well work, painting, etc. The commenter asserted that, if that was BSEE's intent, compliance would be difficult since many products are stored in transporters, drums and buckets. The commenter stated that inclusion of devices such as LSH sensors would serve no useful purpose since they would not have a “source” to shut in, and connecting them to facility safety systems would impose a major burden since they are moved frequently. The commenter asserted that the proposed requirements for venting and/or flame arrestors for drums and transporters are understandable, but requiring full compliance with API RP 14C atmospheric vessel requirements would impose additional burdens that provide no tangible benefits. The commenter provided recommended revisions to the proposed language.
Response—BSEE does not intend to include non-permanent storage of chemicals and other substances used for ancillary operations such as well work, painting, etc., within the scope of this requirement. The relevant tanks are sealed, with no venting or inlet-outlet valves, and they are not connected to the production process train. To clarify this point, BSEE revised this section to exclude U.S. Department of Transportation-approved transport tanks that are sealed and not connected via interconnected piping to the production process train and that are used for storage only of refined liquid hydrocarbons or Class I liquids.
However, BSEE does not agree with the suggestion for requiring the TSE on atmospheric tanks that are not connected via interconnected piping to the production process train because these tanks are sealed,
Comment—A commenter asserted that proposed paragraph (b) would have a huge impact for manufactured “standard” designs currently in service that do not have nozzles for moving level sensors. The commenter asserted that placing LSH sensors in oil buckets may not necessarily reduce risk of pollution, depending on individual equipment design. The commenter added that many systems are configured for the oil bucket level to be much lower than the main compartment level (to prevent overflow of the oil into water) so an LSH sensor in an oil bucket would not sense true “high” levels in the component, requiring two LSH sensors to be installed rather than just relocating the LSH sensor. The commenter claimed that it would be difficult to retrofit vessel oil buckets with an LSH sensor if they do not have the appropriate nozzles and asked whether exceptions would be made for existing equipment currently in service. The commenter provided recommended language to address its concerns.
Response—BSEE agrees with the commenter that the operator must ensure that all atmospheric vessels, whether existing or new, are designed and maintained to ensure the proper working conditions for LSH sensors. Specifically, to ensure proper working conditions for the LSH sensor, the LSH sensor bridle must be designed to prevent different density fluids from impacting sensor functionality. Similarly, for atmospheric vessels that have oil buckets, proper working conditions means the LSH sensor must be installed to sense the level in the oil bucket. This requirement is not just to protect against overflow but also to prevent oily-water interface from going out the water outlet, thus protecting safety and the environment. Thus, for those reasons, BSEE does not agree with the commenter's suggestion to limit the requirements for atmospheric vessels with oil buckets only to new equipment (
Comment—A commenter asserted that the tables in proposed §§ 250.873, 250.874 and 250.875 are inconsistent with the tables issued in NTLs, guidance provided via DWOP approvals, and discussions with BSEE GOM Region's Technical Assessment Section. The commenter recommended that BSEE revisit and revise the tables according to NTL No. 2011-N11 and previous guidance issued to operators as part of the DWOP process.
Response—BSEE agrees with the commenter and has revised the tables to be more consistent with the referenced NTL and BSEE guidance provided to operators during the DWOP process. However, not every detail relevant to subsea gas lift systems can be included in the final rule. There are three different gas lift situations, each using a different system, and the nuances for these systems are better addressed in guidance. BSEE plans to revise the referenced NTL to address those details that are not covered in this final rule.
Comment—A commenter requested that, for clarity, the word “system” should be added after “gas lift” in the first sentence of paragraph (d). The commenter asked why there was no allowable leakage rate specified for the valve in proposed paragraph (d)(1), given that a gas lift isolation valve (GLIV) is required when gas lifting a subsea pipeline, pipeline riser, or manifold via an external gas lift pipeline, as described in proposed paragraph (b)(1).
Response—BSEE agrees with the commenter's suggestions for revising paragraph (d) by adding the word “system” after “gas lift” in the first sentence. No other changes are necessary, however. Under paragraph (b)(1), the GLIV must be installed downstream of the USV(s) and/or AIV(s). The GLIV prevents flow back to the facility. For gas lift of a subsea pipeline, pipeline riser, or manifold via an external gas lift pipeline, the USV is the primary barrier and is leak tested; the GLIV is not the primary barrier, so a leak test is not required.
BSEE revised final paragraph (g) to clarify the testing requirements. In particular, BSEE revised proposed paragraph (g)(2) to address the actions that an operator must take if a designated USV on a WI well fails its test. BSEE retained in the final paragraph the proposed requirement that the operator must designate another certified subsea valve as a USV, in place of the USV that failed its test. However, BSEE added language to clarify that this designation requires District Manager approval. In addition, BSEE removed language from proposed paragraph (g)(2) that would have given the operator the option, in lieu of designating a new certified subsea valve as a USV, to modify the valve closure time of the surface-controlled SSSV or WIV after sensor activation. That situation has never occurred in BSEE's experience; thus, that option is not needed in this regulation.
In consideration of a comment received, the final rule omits language from proposed paragraph (g)(3) that addressed function testing the WISDV in cases where the operator had BSEE's approval not to leak test the WISDV. BSEE has decided that the function testing requirements for WISDVs in such circumstances would be more effectively addressed through other means, such as through a departure approval under § 250.142.
In final paragraph (h)(2), BSEE removed the proposed language stating that the District Manager may order a shut-in when there is a loss of communication during WI operations. The deleted sentences were intended only for informative purposes, not as a regulatory requirement, and thus are not needed in the regulation.
Comment—A commenter asked whether the proposed regulations apply to all WI wells and all WI systems. The commenter asserted that these are `departing pipelines' from the platform, and that the proposed requirement would be inconsistent with API RP 14C.
Response—BSEE disagrees with the commenter, and has determined that no changes are necessary based on this comment. These provisions apply to all WI wells and WI systems. Consistent with existing BSEE policy and guidance previously provided to the operators through the DWOP process, the zero-leak rate for these wells is appropriate, and if the well is capable of natural flow to the surface, then the operator needs to test these valves. Any operator that has concerns with its specific subsea WI system should contact the appropriate District Manager, who will review the concerns on a case-by-case basis.
Comment—A commenter asserted that, because a WIV is defined in § 250.874(a) as a “water injection valve,” and because this definition does not include WISDVs (as defined in § 250.874(b)), the acronym “WIV” as used in proposed paragraphs (g) and (g)(1) should be replaced with the words “water injection system valve.” The commenter also suggested, for clarity, that BSEE add the word “leak” to the first sentence of paragraph (g)(3). The commenter questioned whether the requirement that USVs meet the allowable leakage criteria (in the event that the WISDV cannot be tested because the shut-in tubing pressure of the water injection well is less than the external hydrostatic pressure) means that the USVs are to be tested in the direction of the water injection flow. If that is so, the commenter questioned why the WISDV cannot be tested similarly,
Response—BSEE agrees with the comment that the acronym “WIV” is not appropriate for use in paragraph (g), as proposed, and has replaced the acronym with “injection valve” in the introductory sentence of paragraph (g) and in subparagraph (g)(1) of the final rule. In addition, based on the commenter's questions and concerns related to the requirement in proposed paragraph (g)(3) for testing a USV in the event that a WISDV cannot be tested, BSEE has decided that there are a number of technical issues related to such testing that require further consideration by BSEE and that potentially would be better addressed through guidance rather than by regulations at this time. Accordingly, BSEE has removed the relevant language in proposed paragraph (g)(3) from the final rule. BSEE may issue additional guidance on WISDV testing at a later date.
Comment—A commenter asserted that the tables in the proposed rule are different from previous guidance provided through DWOPs by BSEE GOM Region's Technical Assistance section or NTL No. 2011-N11 (“Subsea Pumping for Producing Operations—Considerations for Using Subsea Gas Lift and Water Flood as Secondary Recovery Methods for Production Operations).” The commenter recommended revising the rule to align with previous guidance issued to operators. The commenter also noted that the proposed rule does not provide the valve closure timing table included as Table 1 in NTL No. 2011-N11 and recommended including the table in the regulation to avoid confusion during the DWOP approval process. The commenter asserted that the “loss of communications” case is addressed in NTL No. 2011-N11, but that the proposed rule did not provide details of how and when to execute an immediate shutdown of a well or subsea boost system. Thus, the commenter requested clarification regarding the shutdown sequence and timing. The commenter also recommended that the tables in the proposed rule be revised to align better with the tables published in the current NTLs.
Response—No changes to this section are necessary in response to these comments. Table 1 from NTL No. 2011-N11, referred to in the comment, is associated with the approval of a specific DWOP. However, the issues associated with that table and these systems are complex, with too many nuances to effectively address in this regulation. Those issues are better addressed through the DWOP process on a case-by-case basis, especially since production systems are site-specific and currently there is no industry standard on subsea pumping. Similarly, under paragraph (d), operators must follow the valve closure times and hydraulic bleed requirements established by their approved DWOPs. Accordingly, BSEE reviews each subsea pumping system individually through the DWOP process. BSEE will review NTL No. 2011-N11 and expects to publish a new NTL consistent with this final rule after the effective date of the final rule.
Comment—One commenter indicated that the proposed requirement potentially could be too broad. The commenter acknowledged that certain intervention activities or changes to software and equipment may justify a complete subsea pump function test—including shutdown, but that other, less significant changes might not warrant such a test. The commenter recommended adding the word “significant” to proposed paragraph (e)(1) so that it reads: “Performing a complete subsea pump function test, including full shutdown after any
Response—BSEE believes that the requirements set forth in paragraph (e)(1) are appropriate and not overbroad under the circumstances; therefore, no changes are necessary at this time. This section deals with newer technology that is still uncommon, and there are currently no well-established industry standards that address how and when function testing of subsea pumps should be conducted. Thus, at present, it is appropriate to require a function test of the subsea pump after any change to software or equipment affecting the subsea pump, whether or not the operator considers the change to be “significant,” in order to ensure that the pump will still function as planned after the change. As BSEE and the industry gain experience under this new requirement, BSEE may consider developing further guidance on when function testing is required under this provision.
Comment—A commenter asked whether the “every 5 years” clock begins the day the proposed regulation is amended or whether the regulation would be retroactive and cause equipment that has not been inspected within the last 5 years to be pulled and inspected.
Response—BSEE revised this section to require the initial inspection within 2 years after the publication of the final rule. The requirement for third-party inspections every 5 years begins to run at the time the initial inspection is completed. This provision is not retroactive.
Comment—BSEE received comments that expressed concern about the safety, costs, and benefits related to removing the fire tube for inspection. Commenters indicated that removing the fire tube for inspection requires removing the components and may require a crane, which the commenters asserted would be a potential safety hazard, as well as very costly, and would not add material value to the inspection process. The commenters suggested that BSEE consider alternatives to removing the tube, such as a visual inspection with the tube in place and an option of removing the tube at the qualified third-party inspector's discretion. They recommended that the fired components be inspected at the same interval as their host equipment. They also stated that expected costs of compliance may exceed BSEE's initial projections, since removing the fire tube may require additional equipment and staff and lead to lost production.
Response—No changes to the regulatory text are necessary. These new requirements are based, in part upon BSEE's investigation of the
BSEE's investigation into the
BSEE agrees, however, that the costs associated with the inspection of fired and exhaust-heated components may be higher than the initial economic analysis estimated and has adjusted those costs in the final economic impact analysis, as discussed in part V of this document. After considering those costs, however, BSEE has concluded that the balance of relevant safety considerations, and other costs and benefits, justify promulgating this final rule.
Final § 250.880(a) includes the notification requirements from existing § 250.804(a)(12) and requires the operator to notify the District Manager at least 72 hours prior to commencing production so that BSEE may conduct a preproduction inspection of the integrated safety system. The final rule retains the existing requirement to notify the District Manager upon actual commencement of production, and adds a new requirement to notify the District Manager and receive approval before certain types of subsea intervention.
The final rule also retains existing testing and inspection requirements,
The following table compares existing allowable leakage rates to the final increased allowable leakage rates for various safety devices:
Additionally, final § 250.880 contains new requirements for BSDVs, changes the testing frequency for underwater safety valves, and adds requirements for the testing of ESD systems, flame, spark, and detonation arrestors, as well as pneumatic/electronic switch LSH and level safety low (LSL) controls. This final section also adds testing and repair/replacement requirements for subsurface safety devices and associated systems on subsea trees and for subsea wells shut-in and disconnected from monitoring capability for greater than 6 months.
Paragraph (c)(2)(iv) was revised to add “gas and/or liquid” before “fluid flow” for consistency with other provisions of the final rule and to clarify that the reference applies to all fluid flow.
Based on consideration of relevant comments, BSEE also revised final paragraph (c)(2)(v) to clarify the meaning of “flowline” FSVs and to remove the references to appendix D, section D4, table D2, and subsection D of API RP 14C (while retaining the requirement to use the test procedure in API RP 14C).
As suggested by comments, BSEE revised paragraph (c)(3)(ii) to include “gas” detection systems. BSEE added a statement in final paragraph (c)(3)(iii)(A) to clarify that the operator must test all stations for functionality at least once each calendar month, not to exceed 6 weeks between tests, and that no station may be reused until all stations have been tested. This revision ensures proper testing of the ESD stations. Similar changes were made, with different timeframes, to paragraphs (c)(3)(iii)(B) and (C).
BSEE restructured proposed paragraph (c)(5), renumbered it as paragraph (d), and revised and reworded many of the subordinate paragraphs for clarity.
BSEE also moved the provision that limits the time (
Subsequent paragraphs were renumbered and revised for clarification. Several paragraphs were also separated into short subparagraphs. BSEE made these changes to make the requirements easier to read and understand. However, BSEE did not make any substantive changes to the requirements in this section.
Comment—BSEE received comments concerning changes to the allowable leakage rate for undersea production systems and BSEE's reasoning for proposing to raise those rates. Multiple commenters mentioned that BSEE based its proposed decision to raise the allowable leakage rate partly on the SWRI report on Project #272. (
Response—BSEE disagrees with the suggestion that the proposed decision on leakage rates was based solely on SWRI report #272. BSEE based its decision to increase allowable leakage rates in production systems on several factors, including industry standards (such as API RP 14B), consistency with prior DWOP approvals, and the SWRI report #272.
BSEE also disagrees with the suggestion that it should not allow any leaking valves as part of an approved safety system. This section specifies the allowable leakage rates for valves that are part of a closed system within the production safety system. There are certain critical valves, such as the BSDV, that cannot have any leakage. There are other valves, however, for which some leakage is allowable. For example, BSEE is increasing the allowable leakage rates on SSSVs, as they are part of a closed safety system, designed to diminish the risk of oil spills by stopping the flow within the system in the event that the riser is damaged. The allowable leakage from SSSVs is contained within the closed system; it is not released into the environment. In addition, these new rates are consistent with accepted industry standards.
Comment—A commenter noted that proposed § 250.880(c)(2) included testing requirements for surface valves. In particular, proposed paragraph (c)(2)(v) would have required testing once each calendar month, not to exceed 6 weeks between tests, and would have also required that all FSVs be tested in accordance with the test procedure specified in API RP 14C, Appendix D, section D4, table D2 subsection D. The commenter asserted that, while this section in API RP 14C appears to apply to flowline FSVs, the proposed regulation was not clear, since it stated that the testing requirements would apply to “surface valves,” including PSVs, Automatic inlet SDVs actuated by a sensor on a vessel or compressor, SDVs in liquid discharge lines and actuated by vessel low-level sensors, and SSVs. Thus, the commenter asserted that this proposed provision would have applied the specific API RP 14C procedure to surface valves throughout the production process and not just valves covered by section A-1 of API RP, 14C which pertains to “Wellheads and Flowlines.” The commenter suggested that, if BSEE intended the proposed testing requirements to apply to “flowline” FSVs, then BSEE should insert “flowline” before “FSVs” in paragraph (c)(2)(v).
Response—BSEE agrees with the substance of this comment and has revised final paragraph (c)(2)(v) to clarify that it applies to flowline FSVs and that flowline FSVs are the only FSVs that must be leak tested under this provision.
Comment—A commenter suggested that BSEE revise proposed § 250.880(c)(3) requirements for fire detections systems to refer to: “Fire (flame, heat, or smoke) and Gas (combustible) detection systems” or that BSEE include a separate item (ix) for combustible gas detection. In addition, the commenter suggested that BSEE remove the proposed requirement that all combustible gas-detection systems must be calibrated every 3 months from proposed paragraph (c)(3)(ii) and move that provision to a separate paragraph on combustible gas detection.
Response—BSEE agrees with the commenter's point that there could have been some confusion between the item names and the testing requirements in paragraph (c)(3)(ii) with regard to gas detection systems. However, instead of adopting all of the changes suggested by the commenter, BSEE revised the item name for final paragraph (c)(3)(ii) to include “gas detection.” This is consistent with API RP14C; and BSEE added the reference to gas detection systems in this paragraph of the final rule to emphasize the need to test those systems.
Comment—BSEE received multiple comments regarding the 3-barrier concept for undersea valves. The commenters expressed concern that the proposed language would not allow sufficient flexibility for compliance. They asserted that some subsea well may not be equipped with more than one USV or an additional tree valve that could serve in that capacity and that not all tree designs can test multiple barriers.
Response—No changes are necessary. BSEE is not aware of any subsea trees that do not have a second USV. Under final paragraph (d) of this section, the 3 pressure barriers are only required in subsea wells that are shut-in and disconnected from monitoring capability for more than 6 months.
Comment—A commenter stated that the proposed rule referred to an inspection requirement that is not included in the existing regulations. The commenter asserted that, under the existing regulations, pumps for firewater systems were required to run and be tested for operation and pressure on a weekly basis, while the proposed rule
Response—No changes are necessary based on this comment. In this section, BSEE is not referencing the entire API RP 14G standard; this provision only refers to section 7.2 of the standard. This annual inspection requirement was added to ensure that the firewater pumps are in good working condition since they are a crucial part of the fire safety system. API RP 14G, section 7.2 provides the appropriate details to ensure that the pump inspection is adequate.
Comment—A commenter asserted that proposed paragraph (c)(5)(v) was confusing and seemed excessive since BSEE had not identified the need for having a drilling vessel “readily available or in the field.” The commenter suggested that BSEE clarify the intent of this proposed rule. The commenter also suggested that BSEE clarify the definition of “in the field or readily accessible” in paragraph (c)(5)(v) and that BSEE should determine that rigs should not have to be under direct contract to be considered “readily accessible.” In addition, the commenter asserted that it is also unclear under what circumstances a “drilling vessel” would be required to intervene in a shut-in well that is disconnected from monitoring capability. The commenter stated that maintaining a rig on standby would not be cost-effective (although the commenter provided no details to support that assertion). The commenter recommended revising paragraph (c)(5)(v) to read: “The designated operator/lessee must ensure that a drilling vessel capable of intervention into the disconnected well must be available to the operator for use should the need arise until the wells are brought on line.”
Response—No changes are necessary based on this comment. The regulation states that the drilling vessel must be “in the field or readily accessible.” This means that a rig needs to be reasonably available; the rule does not state or imply that the drilling vessel must be under direct contract to be considered readily accessible. The regulation is intended to require that an operator have a rig reasonably available that can respond in a reasonable timeframe, and this is only required for subsea wells that are shut-in and disconnected from monitoring capability for periods greater than 6 months. This provision requires this precaution in order to reduce the risks that a prudent operator is reasonably likely to encounter in the event that other safety systems on the well fail.
Comment—A commenter suggested clarifying proposed § 250.880(c)(4)(iii), regarding testing of BSDVs, by inserting the words “and BSDVs” in the third sentence in that paragraph so that it reads: “You must test according to API RP 14H for SSVs and BSDVs (incorporated by reference as specified in § 250.198).” The commenter also suggested revising the next sentence in that paragraph by replacing the phrase “if any fluid flow is observed during the leakage test” with “if fluid leakage exceeding the criteria specified in API RP 14H is observed during the leakage test . . .”.
Response—No changes are necessary based on this comment. The BSDV is the surface equivalent of an SSV on a surface well and is critical to ensuring the safety of personnel on the facility as well as protection of the environment. Because the BSDV is a critical component of the subsea system, it is necessary that this valve has rigorous testing criteria. Thus, the BSDV cannot have any fluid flow during the leakage test.
Comment—One commenter questioned whether the proposed rule would require a facility owner to report a change in the “designated person in charge” of welding—as specified in §§ 250.111 and 250.113—or a change of the “designated person in charge” as required by USCG regulations. The commenter also asked whether the proposed rule would require a facility owner who designates a separate “person in charge” for each of the day and night shifts to submit two reports daily.
Response—BSEE agrees that the proposed language in paragraph (c) was somewhat unclear, and has revised this provision in the final rule to clarify that the person referred to is the “primary point of contact” for the facility, who must be included on the facility's contact list. This section ensures that BSEE has a way to contact the facility, when needed, and does not require daily reporting to BSEE. The operator is required to update this list annually and whenever the contact information changes.
Comment—A commenter requested clarification of the term “platform” as used in proposed paragraph (c). The commenter asked whether that term includes FPSs, FPSOs, TLPs, and MODUs. The commenter also requested clarification on the responsibilities for MODU owners and lease operators for submitting the required contact information if this section does consider MODUs to be platforms.
Response—BSEE agrees that the use of the word “platforms” in paragraph (c) could cause some confusion, so we replaced that term with the word “facilities” in the final rule. For purposes of this paragraph, facilities include FPSs, FPSOs, and TLPs.
Comment—A commenter asserted that this proposed section included no method for BSEE to confirm compliance. The commenter recommended that BSEE consider third-party oversight in the form of an annual inspection of records or spot-checks of material maintenance and management programs. The commenter suggested that BSEE could use the proposed rule section to create positive reinforcement mechanisms.
Response—No changes are necessary based on this comment. BSEE has confidence in its inspection program's ability to confirm compliance. BSEE's inspectors confirm that the operators are in compliance with BSEE regulations through a number of methods, including verifying records and documentation. (
Comment—A commenter questioned whether it was BSEE's intent to remove the prescriptive training requirements of subpart O and replace them with the performance-based requirements of subpart S. If so, the commenter suggested that portions of subpart O should be revoked; if not, the commenter suggested that subpart O as well as subpart S should be referenced.
Response—BSEE agrees with the commenter's suggestion about referring to subpart O in this section. Accordingly, BSEE has changed the section to require that personnel installing, repairing, testing, maintaining, and operating surface and subsurface safety devices, and personnel operating production platforms, be trained according to the procedures in subpart O and subpart S. The requirements of subpart O are not affected by this rule; likewise subpart S neither replaces nor supersedes the requirements in subpart O. Rather, those two subparts complement each other. Subpart S provides the general requirements for training, and subpart O provides more detailed training requirements for well control and production safety. If the operator complies with subpart O, then that operator also meets some of the training requirements for subpart S.
Comment—One commenter asserted that it is important to human and environmental health that oil and gas production companies understand all the requirements and components associated with drilling, and have an effective quality management system in place. The commenter suggested that initial and periodic training sessions be mandatory for all oil and gas production operations employees, and that personnel be properly trained and qualified to perform their assigned functions, in accordance with subpart O.
Response—No changes to this section are needed in response to this comment. Given the multitude of different jobs associated with offshore production, it is impractical for this rule to establish specific training requirements for each job. However, BSEE regulations under subpart S require operators to address appropriate personnel training through their SEMS plans. SEMS requires everyone who works offshore to be “trained in accordance with their duties and responsibilities to work safely and are aware of potential environmental impacts.” § 250.1915. In addition, subpart O provides some specific requirements for training. Among other subpart O requirements, § 250.1503(a) requires operators to implement training programs so that all employees can competently perform their assigned duties, including well control and production safety duties. By requiring operators to ensure that their personnel are trained in accordance with the procedures in subparts O and S, final § 250.891 substantially satisfies the commenter's concern that only qualified personnel perform production operations functions.
Comment—While recognizing the intent behind the proposal to move training from the subpart O requirements to subpart S, one commenter asserted that subpart O is still valid, since it has not been withdrawn from the regulations. The commenter stated that subpart O offers more detail on training program requirements, compared to subpart S, and it is an established basis for all operators' production safety systems and well control training programs. The commenter also asserted that the proposed rule would impose detailed requirements on the operator that are neither specifically required under subpart S nor recommended in API RP 75 (Recommended Practice for Development of a Safety and Environmental Management Program for Offshore Operations and Facilities). The commenter recommended that BSEE revise this section to reflect subpart O and not subpart S.
Response—BSEE largely agrees with the commenter's statements concerning the continued applicability of subpart O training requirements for personnel performing functions covered by this final rule. Proposed § 250.891 was not intended to override subpart O; nor does subpart S replace or supersede the requirements in subpart O. As already discussed, the two subparts complement each other, in general and as applied to subpart H. For that reason, BSEE disagrees with the commenter's suggestion that § 250.891 should not refer to subpart S. To provide additional clarity on these point, BSEE revised final § 250.891 to expressly refer to subpart O as well as subpart S.
E.O. 12866 provides that the Office of Information and Regulatory Affairs (OIRA) will review all significant regulatory actions. A significant regulatory action is one that is likely to result in a rule that:
• Has an annual effect on the economy of $100 million or more, or adversely affects 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;
• Creates serious inconsistency or otherwise interferes with an action taken or planned by another agency;
• Materially alters the budgetary impacts of entitlement grants, user fees, loan programs, or the rights and obligations of recipients thereof; or
• Raises novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in E.O. 12866.
BSEE has concluded, and OIRA has determined, that this rule is not a significant action under E.O. 12866. In particular, BSEE has concluded, and OIRA has determined, that this final rule will not have an annual economic impact of $100 million or more and will not have a material adverse effect on the economy, the environment, public health or safety, or governmental communities. In support of that determination, BSEE prepared an economic analysis to assess the anticipated costs and potential benefits of the rulemaking. The following discussions summarize the final economic analysis; a complete copy of the final economic analysis can be viewed at
As discussed in part II of this document, BSEE identified a need to amend and update the oil and gas production safety system regulations in subpart H. The regulations address such issues as production safety systems, subsurface safety devices, and safety device testing. These systems play a critical role in protecting workers and the environment.
Subpart H has not had a major overhaul since it was first published in 1988. Since that time, much of the oil and gas production on the OCS has moved into deeper waters, and the industry has developed and begun employing new technologies, including: Foam firefighting systems; subsea pumping, water flooding, and gas lift; and new alloys and equipment for high temperature and high pressure wells. The subpart H regulations, however, have not kept pace with the technological advancements. Many of the new provisions in the final rule serve to incorporate and codify current industry practices. In addition, the final rule restructures and reorganizes subpart H into shorter, easier-to-read sections and highlights important information for regulated entities. Thus, the final rule will greatly improve the readability and understanding of the production safety system regulations.
In developing this final rule, BSEE considered two major alternatives (in addition to the numerous specific choices previously described in parts III and IV): (1) Make the regulatory changes contained in this final rule; or (2) take no regulatory action and continue to rely on the current regulations, first promulgated in 1988, in combination with the conditions imposed by subsequent permits and plans (
BSEE has elected to move forward with alternative 1 and finalize this rule, which codifies existing guidance and relevant standards and best industry practices. This alternative will provide industry with regulatory certainty, as well as with an appropriate balance of prescriptive and flexible, performance-based requirements. It will also provide BSEE with the necessary means to ensure that production safety systems will improve safety and environmental protection on the OCS, resulting in the other benefits described in this summary and the full economic analysis. Alternative 2 would be less costly, but would not provide those benefits to industry or the public.
BSEE derived its estimates by comparing the costs and benefits of the new provisions in the final rule to the baseline in accordance with the guidance provided in OMB Circular A-4. In the baseline, BSEE includes costs and benefits of the final rule that already occur as a result of the existing BSEE regulations, industry guidance documents, industry-developed standards and other accepted industry practices with which industry already complies.
Accordingly, the cost estimate in the final economic analysis for the Arctic rule included costs related to some requirements that otherwise could have been included in the economic baseline. (
The analysis identified a total of 18 provisions that will result in changes from the baseline, which are listed in Table 1 below, categorized by the size of the cost that they impose on industry. The size categories were defined as follows: “Major Costs” being costs of at least $1,000 per firm per year, on average as estimated; “Minor Costs” being less than $1,000 and greater than $100 per firm per year; and “Inconsequential Costs” being less than $100 per firm per year. The number of offshore operators is 99. The cost per firm does not include costs to BSEE (which accounted for only about 0.5 percent of all costs of all provisions). As shown in Table 1, the distribution of costs by provision is extremely skewed, with one of the 18 provisions (specifically, § 250.876, “Fired and Exhaust Heated Components”) accounting for over 96 percent of all costs to industry from the rule (about $45,000 per firm per year).
Thus, there is only 1 major cost provision of the final rule. There are 7 minor cost provisions (ranging, on average, from $110 to $576 per firm per year), and 10 inconsequential cost provisions (ranging from $2 to $77 per firm per year). The inconsequential costs, in total, account for only $185 per firm per year, or less than 0.4 percent of the cost of the rule to industry.
The single major cost provision, § 250.876, will require the fire tube for certain tube-type heaters to be removed and inspected, every 5 years by a qualified third-party. In addition, if removal and inspection indicate tube-type heater deficiencies, operators must complete and document repairs or replacements. Inspection results must be documented, retained for at least 5 years, and made available to BSEE upon request.
BSEE estimates that there are approximately 1,500 fired and exhaust heated components on the OCS that will need to be inspected every 5 years. Based on comments submitted on the proposed rule and the experience of BSEE subject matter experts, the cost associated with each component inspection is estimated to be approximately $15,000. We estimated the average number of component inspections to be 300 per year, resulting in an annual cost to industry of $4.5 million for inspection of fired and exhaust heated components.
Table 2 summarizes the total cost for the final rule over 10 years (2016-25) by types of costs, both undiscounted and discounted (using 3 and 7 percent rates).
The final rule will benefit society (including both the general public and the industry) in two ways: (1) By reducing the probability of incidents resulting in oil spills and worker injuries, and the severity of such incidents if they occur; and (2) by generating cost savings through an increase in allowable leakage rates for certain safety valves under final § 250.880, which reduces the need (and therefore the costs) to replace or repair such valves, (without resulting in oil released into the environment, as previously explained in part IV.C of this document). BSEE has also determined that this provision poses no economic costs to the regulated industry, so its potential economic impact on that industry is only beneficial (due to the potential costs savings).
With respect to oil spills and injuries, however, the magnitude of the potential benefits is uncertain and highly dependent on the actual reductions in the probability and severity of oil spills and injuries that the final rule will achieve.
Due to this uncertainty, BSEE could not perform a standard cost-benefit analysis to estimate the net benefits of the final rule. As is common in situations where regulatory benefits are highly uncertain, we conducted a break-even analysis following OMB guidance in Circular A-4. Break-even analysis estimates the minimum risk reduction that the final rule will need to achieve for the rule to be cost-beneficial. This minimum risk reduction is calculated by dividing the total net costs of a regulation by the costs of incidents the regulation is expected to avoid. For this analysis, the total net costs are calculated by subtracting the equipment cost savings associated with increased allowable leakage rates and safety valves from the total cost of the rule. BSEE divided the total net costs by the costs associated with oil spills and injuries that the regulation might prevent to calculate the break-even risk reduction level.
To analyze potential reductions in oil spills that might result from the final rule, BSEE used data on spill incidences on OCS facilities from the BOEM OCS Case Study.
A similar procedure was used to estimate the level of benefits resulting from potentially avoided injuries. (Avoided fatalities were not considered because BSEE determined that there were no past fatalities that could be directly connected to the provisions related to the final rule.) Table 3 presents estimated injury levels (for all BSEE Regions where there has been production activity from 2007 through 2013), which we then used to calculate an annual estimated average number of injuries (214). These injury levels were estimated based on the numbers of past injuries reported to BSEE (or MMS) by facilities that would be affected by the rule. (These estimates are explained in greater detail in the final economic analysis document in the regulatory docket.)
We then used that annual average to estimate the number of injuries that could potentially be avoided by the final rule. BSEE then estimated the corresponding benefits by multiplying the average annual number of avoided injuries (214) by the values ascribed to injuries in previous BSEE regulatory analyses (about $47,000 per injury). These calculations resulted in an annual average of potential avoided cost of injuries of $10.1 million, and potential avoided costs from both spills and injuries of roughly $25.0 million. (
In addition to estimating the break-even risk reduction level (
Using the estimated costs, cost savings, and potential benefits (in terms of avoided costs of oil spill incidents) of the final rule, BSEE calculated the break-even risk reduction level using discount rates of 3 and 7 percent over a period of 10 years.
As presented in Table 5, the break-even risk reduction level is 12.7 percent (undiscounted), 12.2 percent (3 percent discount rate), and 11.6 percent (7 percent discount rate). At these levels of risk reduction, there would be between 25 and 27 fewer injuries each year. This result demonstrates that a relatively small reduction in the risk of oil spill incidents on affected OCS facilities will be needed for the final rule to be cost-beneficial.
For the second set of benefits, identified as a cost savings to industry, BSEE estimated a net cost (total cost minus total savings) for the final rule. To estimate the potential cost savings to operators from no longer needing to repair or replace certain safety valves as often as under the existing rules, due to higher allowable leakage rates under the final rule, BSEE used data from inspection records for OCS facilities affected by the rule. Of the active wells on the OCS, there have been, on average, 57 occurrences per year of valve repair or replacement associated with the existing allowable leakage rates that could be affected by the increased allowable leakage rates under the final rule. Based on comments submitted on the proposed rule and on the experience of BSEE subject matter experts, we estimated that the potential costs from the repair or replacement of the safety valves would be $22,000 in labor costs and an additional $5,000 in equipment replacement costs per repair/replacement. Thus, BSEE estimated the annual avoided costs from increasing the allowable leakage rates for certain valves to be approximately $1.54 million, based on an estimated average of 57 repairs or replacements avoided per year.
After consideration of all of the potential impacts of this final rule, as described here and in the final economic analysis, BSEE has concluded that the societal benefits of the final rule justify the societal costs.
The Regulatory Flexibility Act (RFA), 5 U.S.C. 601-612, requires agencies to analyze the economic impact of regulations when there is likely to be a significant economic impact on a substantial number of small entities and to consider regulatory alternatives that will achieve the agency's goals while minimizing the burden on small entities. Section 605 of the RFA allows an agency to certify a rule, in lieu of preparing an analysis, if the regulation will not have a significant economic impact on a substantial number of small entities. Further, the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), Public Law 104-121, (March 29, 1996), as amended, requires agencies to produce compliance guidance for small entities if the rule has a significant economic impact on a substantial number of small entities.
For the reasons explained in this section, BSEE has determined that the rule is not likely to have a significant economic impact on a substantial number of small entities and, therefore, that a regulatory flexibility analysis for the final rule is not required by the RFA. Nonetheless, we have included the equivalent of a final regulatory flexibility analysis to assess the impact of this rule on small entities, which is included in the full economic analysis available in the public docket for this rulemaking at
The rule is not a major rule under the Small Business Regulatory Enforcement Fairness Act, Public Law 104-121, (March 29, 1996), as amended. This rule:
1. Will not have an annual effect on the economy of $100 million or more. This rule revises the requirements for oil and gas production safety systems. The changes will not have a significant impact on the economy or any economic sector, productivity, jobs, the environment, or other units of government. Most of the new requirements are related to inspection, testing, and paperwork requirements, and will not add significant time to development and production processes. The complete annual compliance cost for each affected small entity is estimated at $8,183.
2. Will not cause a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions.
3. Will 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. The requirements will apply to all entities undertake oil and gas production operations on the OCS.
Your comments are important. The Small Business and Agriculture Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were established to receive comments from small businesses about Federal agency enforcement actions. The Ombudsman will annually evaluate the enforcement activities and rate each agency's responsiveness to small business. If you wish to comment on the actions of BSEE, call 1-888-734-3247. You may comment to the Small Business Administration (SBA) without fear of retaliation. Allegations of discrimination/retaliation filed with the SBA will be investigated for appropriate action.
This rule will not impose an unfunded mandate that may result in State, local, or tribal governments or in private sector expenditures, in the aggregate, of $100 million or more in any one year. The rule will not have a significant or unique effect on State, local, or tribal governments. A statement containing the information required by the Unfunded Mandates Reform Act (2 U.S.C. 1531
Under the criteria in E.O. 12630, this rule does not have significant takings implications. The rule is not a governmental action capable of interfering with constitutionally protected property rights. A Takings Implications Assessment is not required.
Under the criteria in E.O. 13132, this rule does not have federalism implications. This rule will not substantially and directly affect the relationship between the Federal and State governments. To the extent that State and local governments have a role in OCS activities, this rule will not affect that role. A Federalism Assessment is not required.
BSEE has the authority to regulate offshore oil and gas production. State governments do not have authority over offshore oil and gas production on the OCS. None of the changes in this rule will affect areas that are under the jurisdiction of the States. It will not change the way that the States and the Federal government interact, or the way that States interact with private companies.
This rule complies with the requirements of E.O. 12988. Specifically, this rule:
1. Meets the criteria of section 3(a) requiring that all regulations be reviewed to eliminate errors, ambiguity, and be written to minimize litigation; and
2. Meets the criteria of section 3(b)(2) requiring that all regulations be written in clear language and contains clear legal standards.
Under the Department's tribal consultation policy and under the criteria in E.O. 13175, we have evaluated this rule and determined that it has no substantial direct effects on federally recognized Indian tribes and that consultation under the Department's tribal consultation policy is not required.
This rule contains a collection of information that was submitted to the Office of Management and Budget (OMB) for review and approval under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
As previously stated, BSEE received 57 sets of comments from individual entities (companies, industry organizations, or private citizens). BSEE's responses to comments pertaining to the PRA can be found in IV.C. (Response to Comments and Section-by-Section Summary) of this document.
Since the original publication of the proposed rule, the ICR for subpart H has been renewed and as a result some of the burden hours and non-hour cost burdens have increased/decreased based on outreach performed during the renewal process. We have accounted for the revised burdens in this final rule as follows:
§§ 250.814(a), 250.815(b), 250.828(a), and 250.829(b)—NEW: Alternate setting depth requests was identified as information collection (+1 hour);
§§ 250.827 and 250.869(a)(3)—NEW: Alternative Procedures is covered under subpart A (−3 hours);
§ 250.837(b)(2)—Submit plan to shut-in wells affected by a dropped object is covered under APD or APM (−2 hours);
§ 250.841(b)—NEW: Temporary repairs to facility piping requests was identified as information collection (+780 hour);
§ 250.852(c)(2)—NEW: Request a different sized PSV was listed as 1 hour, 1 response, 5 total burden hours, while it should have been 1 hour, 1 response, 1 total burden hour (−4 hours);
§ 250.855(a)—NEW: Uniquely identify all ESD stations (Note: while this is considered usual and customary business practice, not all companies have done this correctly. The burden listed is only for those who have new floating facilities) (+32 hours);
§ 250.876—NEW: Document and retain, for at least 5 years, all tube-type heater information/requirements; make available to BSEE upon request (+300 hours);
§ 250.880(a)(3)—NEW: Notify BSEE and receive approval before performing modifications to existing subsea infrastructure (+10 hours);
§ 250.802(c)(1)—NEW: Independent third-party for reviewing and certifying various statements (+$550,000);
§ 250.861(b)—NEW: Send foam concentrate sample(s) to authorized representative for quality condition testing (+$209,000); and
§ 250.876—NEW: Have qualified third party remove and inspect, and repair or replace as needed, fire tube (+$4,500,000).
Also, between the proposed and final rulemaking, the cost recovery fees under 30 CFR 250.125 increased based on a final rule published on October 1, 2013 (78 FR 60208), which affects several of the applications subject to this final rule. The most current approved fees and burden hours pertaining to subpart H are listed in the following burden table. While the fees for each affected application increased, the number of applications went down and the remainder of the regulatory requirement burdens in the ICR increased. These changes resulted in a net decrease for non-hour cost burdens (−$20,313) and a net increase for burden hours (+29,218).
As stated previously, this final rule also applies to one regulation under 30 CFR part 250, subpart A, General (§ 250.107(c)). Once this final rule becomes effective, the paperwork burden associated with subpart A will be removed from this collection of information and consolidated with the IC burdens under OMB Control Number 1014-0022.
An agency 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. The public may comment, at any time, on the accuracy of the IC burden in this rule and may submit any comments to DOI/BSEE; ATTN: Regulations and Standards Branch; VAE-ORP; 45600 Woodland Road, Sterling, VA 20166; email
We prepared a final environmental assessment to determine whether this final rule will have a significant impact on the quality of the human environment under NEPA and have concluded that it will not have such an impact. This rule does not constitute a major Federal action significantly affecting the quality of the human environment. A detailed statement under NEPA is not required because we reached a Finding of No Significant Impact. A copy of the Environmental Assessment and Finding of No Significant Impact can be viewed at
In developing this rule we did not conduct or use a study, experiment, or survey requiring peer review under the Data Quality Act (Pub. L. 106-554, app. C sec. 515, 114 Stat. 2763, 2763A-153-154).
This rule is not likely to have a significant adverse effect on the supply, distribution, or use of energy, and therefore it is not a significant energy action under the definition in E.O. 13211. A Statement of Energy Effects is not required.
Administrative practice and procedure, Continental shelf, Environmental impact statements, Environmental protection, Government contracts, Incorporation by reference, Investigations, Oil and gas exploration, Penalties, Pipelines, Outer Continental Shelf—mineral resources, Outer Continental Shelf—rights-of-way, Reporting and recordkeeping requirements, Sulfur.
For the reasons stated in the preamble, the Bureau of Safety and Environmental Enforcement (BSEE) amends 30 CFR part 250 as follows:
30 U.S.C. 1751; 31 U.S.C. 9701; 33 U.S.C. 1321(j)(1)(C); 43 U.S.C. 1334.
(c)
(2) Conformance with BSEE regulations will be presumed to constitute the use of BAST unless and until the Director determines that other technologies are required pursuant to paragraph (c)(1) of this section.
(3) The Director may waive the requirement to use BAST on a category of existing operations if the Director determines that use of BAST by that category of existing operations would not be practicable. The Director may waive the requirement to use BAST on an existing operation at a specific facility if you submit a waiver request demonstrating that the use of BAST would not be practicable.
(a) * * *
The revisions and addition read as follows:
(g) * * *
(1) ANSI/ASME Boiler and Pressure Vessel Code, Section I, Rules for Construction of Power Boilers; including Appendices, 2004 Edition; and July 1, 2005 Addenda, and all Section I Interpretations Volume 55, incorporated by reference at §§ 250.851(a) and 250.1629(b).
(2) ANSI/ASME Boiler and Pressure Vessel Code, Section IV, Rules for Construction of Heating Boilers; including Appendices 1, 2, 3, 5, 6, and Non-mandatory Appendices B, C, D, E, F, H, I, K, L, and M, and the Guide to Manufacturers Data Report Forms, 2004 Edition; July 1, 2005 Addenda, and all Section IV Interpretations Volume 55, incorporated by reference at §§ 250.851(a) and 250.1629(b).
(3) ANSI/ASME Boiler and Pressure Vessel Code, Section VIII, Rules for Construction of Pressure Vessels; Divisions 1 and 2, 2004 Edition; July 1, 2005 Addenda, Divisions 1, 2, and 3 and all Section VIII Interpretations Volumes 54 and 55, incorporated by reference at §§ 250.851(a) and 250.1629(b).
(h) * * *
(1) API 510, Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration, Downstream Segment, Ninth Edition, June 2006; incorporated by reference at §§ 250.851(a) and 250.1629(b);
(51) API RP 2RD, Recommended Practice for Design of Risers for Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs), First Edition, June 1998; reaffirmed, May 2006, Errata, June 2009; incorporated by reference at §§ 250.292, 250.733, 250.800(c), 250.901(a), (d), and 250.1002(b);
(52) API RP 2SK, Recommended Practice for Design and Analysis of Stationkeeping Systems for Floating Structures, Third Edition, October 2005, Addendum, May 2008; incorporated by reference at §§ 250.800(c) and 250.901(a), (d);
(53) API RP 2SM, Recommended Practice for Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, First Edition, March 2001, Addendum, May 2007; incorporated by reference at §§ 250.800(c) and 250.901;
(55) ANSI/API RP 14B, Recommended Practice for Design, Installation, Repair and Operation of Subsurface Safety Valve Systems, Fifth Edition, October 2005; incorporated by reference at §§ 250.802(b), 250.803(a), 250.814(d), 250.828(c), and 250.880(c);
(56) API RP 14C, Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms, Seventh Edition, March 2001, Reaffirmed: March 2007; incorporated by reference at §§ 250.125(a), 250.292(j), 250.841(a), 250.842(a), 250.850, 250.852(a), 250.855, 250.856(a), 250.858(a), 250.862(e), 250.865(a), 250.867(a), 250.869(a) through (c), 250.872(a), 250.873(a), 250.874(a), 250.880(b) and (c), 250.1002(d), 250.1004(b), 250.1628(c) and (d), 250.1629(b), and 250.1630(a);
(57) API RP 14E, Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems, Fifth Edition, October 1991; Reaffirmed, January 2013; incorporated by reference at §§ 250.841(b), 250.842(a), and 250.1628(b) and (d);
(58) API RP 14F, Recommended Practice for Design, Installation, and Maintenance of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class 1, Division 1 and Division 2 Locations, Upstream Segment, Fifth Edition, July 2008, Reaffirmed: April 2013; incorporated by reference at §§ 250.114(c), 250.842(b), 250.862(e), and 250.1629(b);
(59) API RP 14FZ, Recommended Practice for Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1 and Zone 2 Locations, First Edition, September 2001, Reaffirmed: March 2007; incorporated by reference at §§ 250.114(c), 250.842(b), 250.862(e), and 250.1629(b);
(60) API RP 14G, Recommended Practice for Fire Prevention and Control on Fixed Open-type Offshore Production Platforms, Fourth Edition, April 2007; incorporated by reference at §§ 250.859(a), 250.862(e), 250.880(c), and 250.1629(b);
(61) API RP 14H, Recommended Practice for Installation, Maintenance and Repair of Surface Safety Valves and Underwater Safety Valves Offshore, Fifth Edition, August 2007; incorporated by reference at §§ 250.820, 250.834, 250.836, and 250.880(c);
(62) API RP 14J, Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities, Second Edition, May 2001; Reaffirmed: January 2013; incorporated by reference at §§ 250.800(b) and (c), 250.842(b), and 250.901(a);
(65) API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2, Second Edition, November 1997; Errata (August 17, 1998), Reaffirmed November 2002; incorporated by reference at
(66) API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2, First Edition, November 1997; Reaffirmed, August 2013; incorporated by reference at §§ 250.114(a), 250.459, 250.842(a), 250.862(a) and (e), 250.872(a), 250.1628(b) and (d), and 250.1629(b);
(68) ANSI/API Specification Q1 (ANSI/API Spec. Q1), Specification for Quality Programs for the Petroleum, Petrochemical and Natural Gas Industry, Eighth Edition, December 2007, Addendum 1, June 2010; incorporated by reference at §§ 250.730, 250.801(b) and (c);
(70) ANSI/API Specification 6A (ANSI/API Spec. 6A), Specification for Wellhead and Christmas Tree Equipment, Nineteenth Edition, July 2004; Errata 1 (September 2004), Errata 2 (April 2005), Errata 3 (June 2006) Errata 4 (August 2007), Errata 5 (May 2009), Addendum 1 (February 2008), Addenda 2, 3, and 4 (December 2008); incorporated by reference at §§ 250.730, 250.802(a), 250.803(a), 250.833, 250.873(b), 250.874(g), and 250.1002(b);
(71) API Spec. 6AV1, Specification for Verification Test of Wellhead Surface Safety Valves and Underwater Safety Valves for Offshore Service, First Edition, February 1, 1996; reaffirmed April 2008; incorporated by reference at §§ 250.802(a), 250.833, 250.873(b), and 250.874(g);
(73) ANSI/API Spec. 14A, Specification for Subsurface Safety Valve Equipment, Eleventh Edition, October 2005, Reaffirmed, June 2012; incorporated by reference at §§ 250.802(b) and 250.803(a);
(74) ANSI/API Spec. 17J, Specification for Unbonded Flexible Pipe, Third Edition, July 2008, incorporated by reference at §§ 250.852(e), 250.1002(b), and 250.1007(a).
(93) ANSI/API Specification 17D, Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment, Second Edition, May 2011, incorporated by reference at § 250.730;
(94) ANSI/API Recommended Practice 17H, Remotely Operated Vehicle Interfaces on Subsea Production Systems, First Edition, July 2004, Reaffirmed January 2009, incorporated by reference at § 250.734;
(95) ANSI/API RP 2N, Third Edition, “Recommended Practice for Planning, Designing, and Constructing Structures and Pipelines for Arctic Conditions”, Third Edition, April 2015; incorporated by reference at § 250.470(g); and
(96) API 570 Piping Inspection Code: In-service Inspection, Rating, Repair, and Alteration of Piping Systems, Third Edition, November 2009; incorporated by reference at § 250.841(b).
(d) Subsurface safety equipment must be installed, maintained, and tested in compliance with the applicable sections in §§ 250.810 through 250.839.
(d) Subsurface safety equipment must be installed, maintained, and tested in compliance with the applicable sections in §§ 250.810 through 250.839.
(a) You must design, install, use, maintain, and test production safety equipment in a manner to ensure the safety and protection of the human, marine, and coastal environments. For production safety systems operated in subfreezing climates, you must use equipment and procedures that account for floating ice, icing, and other extreme environmental conditions that may occur in the area. You must not commence production until BSEE approves your production safety system application and you have requested a preproduction inspection.
(b) For all new production systems on fixed leg platforms, you must comply with API RP 14J (incorporated by reference as specified in § 250.198);
(c) For all new floating production systems (FPSs) (
(1) Comply with API RP 14J;
(2) Meet the production riser standards of API RP 2RD (incorporated by reference as specified in § 250.198), provided that you may not install single bore production risers from floating production facilities;
(3) Design all stationkeeping (
(4) Design stationkeeping (
(d) If there are any conflicts between the documents incorporated by reference and the requirements of this subpart, you must follow the requirements of this subpart.
(e) You may use alternate procedures or equipment during operations after receiving approval from the District Manager. You must present your proposed alternate procedures or equipment as required by § 250.141.
(f) You may apply for a departure from the operating requirements of this subpart as provided by § 250.142. Your written request must include a justification showing why the departure is necessary and appropriate.
(a)
(1) Surface safety valves (SSV) and actuators, including those installed on injection wells capable of natural flow;
(2) Boarding shutdown valves (BSDV) and their actuators, as of September 7, 2017. For subsea wells, the BSDV is the surface equivalent of an SSV on a surface well;
(3) Underwater safety valves (USV) and actuators; and
(4) Subsurface safety valves (SSSV) and associated safety valve locks and landing nipples.
(b)
(c)
(a) All SSVs, BSDVs, and USVs and their actuators must meet all of the specifications contained in ANSI/API Spec. 6A and API Spec. 6AV1 (both incorporated by reference as specified in § 250.198).
(b) All SSSVs and their actuators must meet all of the specifications and recommended practices of ANSI/API Spec. 14A and ANSI/API RP 14B, including all annexes (both incorporated by reference as specified in § 250.198). Subsurface-controlled SSSVs are not allowed on subsea wells.
(c) Requirements derived from the documents incorporated in this section for SSVs, BSDVs, USVs, and SSSVs and their actuators, include, but are not limited to, the following:
(1) Each device must be designed to function and to close in the most extreme conditions to which it may be exposed, including temperature, pressure, flow rates, and environmental conditions. You must have an independent third-party review and certify that each device will function as designed under the conditions to which it may be exposed. The independent third-party must have sufficient expertise and experience to perform the review and certification.
(2) All materials and parts must meet the original equipment manufacturer specifications and acceptance criteria.
(3) The device must pass applicable validation tests and functional tests performed by an API-licensed test agency.
(4) You must have requalification testing performed following manufacture design changes.
(5) You must comply with and document all manufacturing, traceability, quality control, and inspection requirements.
(6) You must follow specified installation, testing, and repair protocols.
(7) You must use only qualified parts, procedures, and personnel to repair or redress equipment.
(d) You must install and use SPPE according to the following table.
(e) You must retain all documentation related to the manufacture, installation, testing, repair, redress, and performance of the SPPE until 1 year after the date of decommissioning of the equipment.
(a) You must follow the failure reporting requirements contained in section 10.20.7.4 of API Spec. 6A for SSVs, BSDVs, and USVs and section 7.10 of API Spec. 14A and Annex F of API RP 14B for SSSVs (all incorporated by reference in § 250.198). You must provide a written notice of equipment failure to the Chief, Office of Offshore Regulatory Programs or to the Chief's designee and to the manufacturer of such equipment within 30 days after the discovery and identification of the failure. A failure is any condition that prevents the equipment from meeting the functional specification or purpose.
(b) You must ensure that an investigation and a failure analysis are performed within 120 days of the failure to determine the cause of the failure. If the investigation and analyses are performed by an entity other than the manufacturer, you must ensure that manufacturer and the Chief, Office of Offshore Regulatory Programs or the Chief's designee receives a copy of the analysis report. You must also ensure that the results of the investigation and any corrective action are documented in the analysis report.
(c) If the equipment manufacturer notifies you that it has changed the design of the equipment that failed or if you have changed operating or repair procedures as a result of a failure, then you must, within 30 days of such changes, report the design change or modified procedures in writing to the Chief, Office of Offshore Regulatory Programs or the Chief's designee.
(d) Any notifications or reports submitted to the Chief, Office of Offshore Regulatory Programs under paragraphs (a), (b), and (c) of this section must be sent to: Bureau of Safety and Environmental Enforcement; VAE-ORP, 45600 Woodland Road, Sterling, VA 20166.
(a) If you plan to install SSSVs and related equipment in an HPHT environment, you must submit detailed information with your Application for Permit to Drill (APD) or Application for Permit to Modify (APM), and Deepwater Operations Plan (DWOP) that demonstrates the SSSVs and related equipment are capable of performing in the applicable HPHT environment. Your detailed information must include the following:
(1) A discussion of the SSSVs' and related equipment's design verification analyses;
(2) A discussion of the SSSVs' and related equipment's design validation and functional testing processes and procedures used; and
(3) An explanation of why the analyses, processes, and procedures ensure that the SSSVs and related equipment are fit-for-service in the applicable HPHT environment.
(b) For this section, HPHT environment means when one or more of the following well conditions exist:
(1) The completion of the well requires completion equipment or well control equipment assigned a pressure rating greater than 15,000 psia or a temperature rating greater than 350 degrees Fahrenheit;
(2) The maximum anticipated surface pressure or shut-in tubing pressure is greater than 15,000 psia on the seafloor for a well with a subsea wellhead or at the surface for a well with a surface wellhead; or
(3) The flowing temperature is equal to or greater than 350 degrees Fahrenheit on the seafloor for a well with a subsea wellhead or at the surface for a well with a surface wellhead.
(c) For this section, related equipment includes wellheads, tubing heads, tubulars, packers, threaded connections, seals, seal assemblies, production trees, chokes, well control equipment, and any other equipment that will be exposed to the HPHT environment.
(a) In zones known to contain hydrogen sulfide (H
(b) You must receive approval through the DWOP process (§§ 250.286 through 250.295) for production operations in HPHT environments known to contain H
For wells using dry trees or for which you intend to install dry trees, you must equip all tubing installations open to hydrocarbon-bearing zones with subsurface safety devices that will shut off the flow from the well in the event of an emergency unless, after you submit a request containing a justification, the District Manager determines the well to be incapable of natural flow. You must install flow couplings above and below the subsurface safety devices. These subsurface safety devices include the following devices and any associated safety valve lock and landing nipple:
(a) An SSSV, including either:
(1) A surface-controlled SSSV; or
(2) A subsurface-controlled SSSV.
(b) An injection valve.
(c) A tubing plug.
(d) A tubing/annular subsurface safety device.
All surface-controlled and subsurface-controlled SSSVs, safety valve locks, and landing nipples installed in the OCS must conform to the requirements specified in §§ 250.801 through 250.803.
You must equip all tubing installations open to a hydrocarbon-bearing zone that is capable of natural flow with a surface-controlled SSSV, except as specified in §§ 250.813, 250.815, and 250.816.
(a) The surface controls must be located on the site or at a BSEE-approved remote location. You may request District Manager approval to
(b) You must equip dry tree wells not previously equipped with a surface-controlled SSSV, and dry tree wells in which a surface-controlled SSSV has been replaced with a subsurface-controlled SSSV, with a surface-controlled SSSV when the tubing is first removed and reinstalled.
You may submit an APM or a request to the District Manager for approval to equip a dry tree well with a subsurface-controlled SSSV in lieu of a surface-controlled SSSV, if the subsurface-controlled SSSV is installed in a well equipped with a surface-controlled SSSV that has become inoperable and cannot be repaired without removal and reinstallation of the tubing. If you remove and reinstall the tubing, you must equip the well with a surface-controlled SSSV.
You must design, install, and operate (including repair, maintain, and test) an SSSV to ensure its reliable operation.
(a) You must install the SSSV at a depth at least 100 feet below the mudline within 2 days after production is established. When warranted by conditions such as permafrost, unstable bottom conditions, hydrate formation, or paraffin problems, the District Manager may approve an alternate setting depth on a case-by-case basis.
(b) The well must not be open to flow while the SSSV is inoperable, except when flowing the well is necessary for a particular operation such as cutting paraffin or performing other routine operations as defined in § 250.601.
(c) Until the SSSV is installed, the well must be attended in the immediate vicinity so that any necessary emergency actions can be taken while the well is open to flow. During testing and inspection procedures, the well must not be left unattended while open to production unless you have installed a properly operating SSSV in the well.
(d) You must design, install, maintain, inspect, repair, and test all SSSVs in accordance with API RP 14B (incorporated by reference as specified in § 250.198). For additional SSSV testing requirements, refer to § 250.880.
(a) You must equip all new dry tree completions (perforated but not placed on production) and completions that are shut-in for a period of 6 months with one of the following:
(1) A pump-through-type tubing plug;
(2) A surface-controlled SSSV, provided the surface control has been rendered inoperative; or
(3) An injection valve capable of preventing backflow.
(b) When warranted by conditions such as permafrost, unstable bottom conditions, hydrate formation, and paraffin problems, the District Manager must approve the setting depth of the subsurface safety device for a shut-in well on a case-by-case basis.
You must install a surface-controlled SSSV or an injection valve capable of preventing backflow in all injection wells. This requirement is not applicable if the District Manager determines that the well is incapable of natural flow. You must verify the no-flow condition of the well annually.
(a) You may remove a wireline- or pumpdown-retrievable subsurface safety device without further authorization or notice, for a routine operation that does not require BSEE approval of a Form BSEE-0124, Application for Permit to Modify (APM). For a list of these routine operations, see § 250.601. The removal period must not exceed 15 days.
(b) Prior to removal, you must identify the well by placing a sign on the wellhead stating that the subsurface safety device was removed. You must note the removal of the subsurface safety device in the records required by § 250.890. If the master valve is open, you must ensure that a trained person (see § 250.891) is in the immediate vicinity to attend the well and take any necessary emergency actions.
(c) You must monitor a platform well when a subsurface safety device has been removed, but a person does not need to remain in the well-bay area continuously if the master valve is closed. If the well is on a satellite structure, it must be attended by a support vessel, or a pump-through plug must be installed in the tubing at least 100 feet below the mudline and the master valve must be closed, unless otherwise approved by the appropriate District Manager.
(d) You must not allow the well to flow while the subsurface safety device is removed, except when it is necessary for the particular operation for which the SSSV is removed. The provisions of this paragraph are not applicable to the testing and inspection procedures specified in § 250.880.
(a) You must equip all tubing installations that have a wireline- or pumpdown-retrievable subsurface safety device with a landing nipple, with flow couplings or other protective equipment above and below it to provide for the setting of the device.
(b) The control system for all surface-controlled SSSVs must be an integral part of the platform emergency shutdown system (ESD).
(c) In addition to the activation of the ESD by manual action on the platform, the system may be activated by a signal from a remote location. Surface-controlled SSSVs must close in response to shut-in signals from the ESD and in response to the fire loop or other fire detection devices.
All wellhead SSVs and their actuators must conform to the requirements specified in §§ 250.801 through 250.803.
You must install, maintain, inspect, repair, and test all SSVs in accordance with API RP 14H (incorporated by reference as specified in § 250.198). If any SSV does not operate properly, or if any gas and/or liquid fluid flow is observed during the leakage test as described in § 250.880, then you must shut-in all sources to the SSV and repair or replace the valve before resuming production.
(a) In the event of an emergency, such as an impending National Weather Service-named tropical storm or hurricane:
(1) Any well not yet equipped with a subsurface safety device and that is capable of natural flow must have the subsurface safety device properly installed as soon as possible, with due consideration being given to personnel safety.
(2) You must shut-in (by closing the SSV and the surface-controlled SSSV) the following types of wells:
(i) All oil wells, and
(ii) All gas wells requiring compression.
(b) Closure of the SSV must not exceed 45 seconds after automatic detection of an abnormal condition or actuation of an ESD. The surface-controlled SSSV must close within 2 minutes after the shut-in signal has closed the SSV. The District Manager must approve any alternative design-delayed closure time of greater than 2
(a) For wells using subsea (wet) trees or for which you intend to install subsea trees, you must equip all tubing installations open to hydrocarbon-bearing zones with subsurface safety devices that will shut off the flow from the well in the event of an emergency. You must also install flow couplings above and below the subsurface safety devices. For instances where the well at issue is incapable of natural flow, you may seek District Manager approval for using alternative procedures or equipment, if you propose to use a subsea safety system that is not capable of shutting off the flow from the well in the event of an emergency. Subsurface safety devices include the following and any associated safety valve lock and landing nipple:
(1) A surface-controlled SSSV;
(2) An injection valve;
(3) A tubing plug; and
(4) A tubing/annular subsurface safety device.
(b) After installing the subsea tree, but before the rig or installation vessel leaves the area, you must test all valves and sensors to ensure that they are operating as designed and meet all the conditions specified in this subpart.
All SSSVs, safety valve locks, and landing nipples installed on the OCS must conform to the requirements specified in §§ 250.801 through 250.803 and any Deepwater Operations Plan (DWOP) required by §§ 250.286 through 250.295.
You must equip all tubing installations open to a hydrocarbon-bearing zone that is capable of natural flow with a surface-controlled SSSV, except as specified in §§ 250.829 and 250.830. The surface controls must be located on the host facility.
You must design, install, and operate (including repair, maintain, and test) an SSSV to ensure its reliable operation.
(a) You must install the SSSV at a depth at least 100 feet below the mudline. When warranted by conditions, such as unstable bottom conditions, permafrost, hydrate formation, or paraffin problems, the District Manager may approve an alternate setting depth on a case-by-case basis.
(b) The well must not be open to flow while an SSSV is inoperable, unless specifically approved by the District Manager in an APM.
(c) You must design, install, maintain, inspect, repair, and test all SSSVs in accordance with your Deepwater Operations Plan (DWOP) and API RP 14B (incorporated by reference as specified in § 250.198). For additional SSSV testing requirements, refer to § 250.880.
(a) You must equip all new subsea tree completions (perforated but not placed on production) and completions shut-in for a period of 6 months with one of the following:
(1) A pump-through-type tubing plug;
(2) An injection valve capable of preventing backflow; or
(3) A surface-controlled SSSV, provided the surface control has been rendered inoperative. For purposes of this section, a surface-controlled SSSV is considered inoperative if, for a direct hydraulic control system, you have bled the hydraulics from the control line and have isolated it from the hydraulic control pressure. If your controls employ an electro-hydraulic control umbilical and the hydraulic control pressure to the individual well cannot be isolated, a surface-controlled SSSV is considered inoperative if you perform the following:
(i) Disable the control function of the surface-controlled SSSV within the logic of the programmable logic controller which controls the subsea well;
(ii) Place a pressure alarm high on the control line to the surface-controlled SSSV of the subsea well; and
(iii) Close the USV and at least one other tree valve on the subsea well.
(b) When warranted by conditions, such as unstable bottom conditions, permafrost, hydrate formation, and paraffin problems, the District Manager must approve the setting depth of the subsurface safety device for a shut-in well on a case-by-case basis.
You must install a surface-controlled SSSV or an injection valve capable of preventing backflow in all injection wells. This requirement is not applicable if the District Manager determines that the well is incapable of natural flow. You must verify the no-flow condition of the well annually.
If a necessary alteration or disconnection of the pipeline or umbilical of any subsea well would affect your ability to monitor casing pressure or to test any subsea valves or equipment, you must contact the appropriate District Office at least 48 hours in advance and submit a repair or replacement plan to conduct the required monitoring and testing. You must not alter or disconnect until the repair or replacement plan is approved.
(a) You must equip all tubing installations that have a wireline- or pump down-retrievable subsurface safety device installed after May 31, 1988, with a landing nipple, with flow couplings, or other protective equipment above and below it to provide for the setting of the device.
(b) The control system for all surface-controlled SSSVs must be an integral part of the platform ESD.
(c) In addition to the activation of the ESD by manual action on the platform, the system may be activated by a signal from a remote location.
All USVs, including those designated as primary or secondary, and any alternate isolation valve (AIV) that acts as a USV, if applicable, and their actuators, must conform to the requirements specified in §§ 250.801 through 250.803. A production master or wing valve may qualify as a USV under API Spec. 6A and API Spec. 6AV1 (both incorporated by reference as specified in § 250.198).
(a) Primary USV (USV1). You must install and designate one USV on a subsea tree as the USV1. The USV1 must be located upstream of the choke valve. As provided in paragraph (b) of this section, you must inform BSEE if the primary USV designation changes.
(b) Secondary USV (USV2). You may equip your tree with two or more valves qualified to be designated as a USV, one of which may be designated as the USV2. If the USV1 fails to operate properly or exhibits a leakage rate greater than allowed in § 250.880, you must notify the appropriate District Office and designate the USV2 or another qualified valve (
You must install, maintain, inspect, repair, and test any valve designated as the primary USV in accordance with this subpart, your DWOP (as specified in §§ 250.286 through 250.295), and API RP 14H (incorporated by reference as specified in § 250.198). For additional USV testing requirements, refer to § 250.880.
You must install a BSDV on the pipeline boarding riser. All new BSDVs and any BSDVs removed from service for remanufacturing or repair and their actuators installed on the OCS must meet the requirements specified in §§ 250.801 through 250.803. In addition, you must:
(a) Ensure that the internal design pressure(s) of the pipeline(s), riser(s), and BSDV(s) is fully rated for the maximum pressure of any input source and complies with the design requirements set forth in subpart J, unless BSEE approves an alternate design.
(b) Use a BSDV that is fire rated for 30 minutes, and is pressure rated for the maximum allowable operating pressure (MAOP) approved in your pipeline application.
(c) Locate the BSDV within 10 feet of the first point of access to the boarding pipeline riser (
(d) Install a temperature safety element (TSE) and locate it within 5 feet of each BSDV.
You must install, inspect, maintain, repair, and test all new BSDVs and BSDVs that you remove from service for remanufacturing or repair in accordance with API RP 14H (incorporated by reference as specified in § 250.198) for SSVs. If any BSDV does not operate properly or if any gas fluid and/or liquid fluid flow is observed during the leakage test, as described in § 250.880, you must shut-in all sources to the BSDV and immediately repair or replace the valve.
(a) In the event of an emergency, such as an impending named tropical storm or hurricane, you must shut-in all subsea wells unless otherwise approved by the District Manager. A shut-in is defined as a closed BSDV, USV, and surface-controlled SSSV.
(b) When operating a mobile offshore drilling unit (MODU) or other type of workover vessel in an area with producing subsea wells, you must:
(1) Suspend production from all such wells that could be affected by a dropped object, including upstream wells that flow through the same pipeline; or
(2) Establish direct, real-time communications between the MODU or other type of workover vessel and the production facility control room and prepare a plan to be submitted to the appropriate District Manager for approval, as part of an Application for Permit to Drill (BSEE-0123) or an Application for Permit to Modify (BSEE-0124), to shut-in any wells that could be affected by a dropped object. If an object is dropped, the driller (or other authorized rig floor personnel) must immediately secure the well directly under the MODU or other type of workover vessel using the ESD station near the driller's console while simultaneously communicating with the platform to shut-in all affected wells. You must also maintain without disruption, and continuously verify, communication between the platform and the MODU or other type of workover vessel. If communication is lost between the MODU or other type of workover vessel and the platform for 20 minutes or more, you must shut-in all wells that could be affected by a dropped object.
(c) In the event of an emergency, you must operate your production system according to the valve closure times in the applicable tables in §§ 250.838 and 250.839 for the following conditions:
(1)
(2)
(3)
(4)
(5)
(d) Following an ESD or fire, you must bleed your low pressure (LP) and high pressure (HP) hydraulic systems in accordance with the applicable tables in §§ 250.838 and 250.839 to ensure that the valves are locked out of service and cannot be reopened inadvertently.
(a) If you have an electro-hydraulic control system, you must:
(1) Design the subsea control system to meet the valve closure times listed in paragraphs (b) and (d) of this section or your approved DWOP; and
(2) Verify the valve closure times upon installation. The District Manager may require you to verify the closure time of the USV(s) through visual authentication by diver or ROV.
(b) You must comply with the maximum allowable valve closure times and hydraulic system bleeding requirements listed in the following table or your approved DWOP as long as communication is maintained with the platform or with the MODU or other type of workover vessel:
(c) If you have an electro-hydraulic control system and experience a loss of communications (EH Loss of Comms), you must comply with the following:
(1) If you can meet the EH Loss of Comms valve closure timing conditions specified in the table in paragraph (d) of this section, you must notify the appropriate District Office within 12 hours of detecting the loss of communication.
(2) If you cannot meet the EH Loss of Comms valve closure timing conditions specified in the table in paragraph (d) of this section, you must notify the appropriate District Office immediately after detecting the loss of communication. You must shut-in production by initiating a bleed of the low pressure (LP) hydraulic system or the high pressure (HP) hydraulic system within 120 minutes after loss of communication. You must bleed the other hydraulic system within 180 minutes after loss of communication.
(3) You must obtain approval from the appropriate District Manager before continuing to produce after loss of communication when you cannot meet the EH Loss of Comms valve closure times specified in the table in paragraph (d) of this section. In your request, include an alternate valve closure timing table that your system is able to achieve. The appropriate District Manager may also approve an alternate hydraulic bleed schedule to allow for hydrate mitigation and orderly shut-in.
(d) If you experience a loss of communications, you must comply with the maximum allowable valve closure times and hydraulic system bleeding requirements listed in the following table or your approved DWOP:
(a) If you have a direct-hydraulic control system, you must:
(1) Design the subsea control system to meet the valve closure times listed in this section or your approved DWOP; and
(2) Verify the valve closure times upon installation. The District Manager may require you to verify the closure time of the USV(s) through visual authentication by diver or ROV.
(b) You must comply with the maximum allowable valve closure times and hydraulic system bleeding requirements listed in the following table or your approved DWOP:
You must design, install, and maintain all production facilities and equipment including, but not limited to, separators, treaters, pumps, heat exchangers, fired components, wellhead injection lines, compressors, headers, and flowlines in a manner that is efficient, safe, and protects the environment.
(a) You must protect all platform production facilities with a basic and ancillary surface safety system designed, analyzed, installed, tested, and maintained in operating condition in accordance with the provisions of API RP 14C (incorporated by reference as specified in § 250.198). If you use processing components other than those for which Safety Analysis Checklists are included in API RP 14C, you must utilize the analysis technique and documentation specified in API RP 14C to determine the effects and requirements of these components on the safety system. Safety device requirements for pipelines are contained in § 250.1004.
(b) You must design, install, inspect, repair, test, and maintain in operating condition all platform production process piping in accordance with API RP 14E and API 570 (both incorporated by reference as specified in § 250.198). The District Manager may approve temporary repairs to facility piping on a case-by-case basis for a period not to exceed 30 days.
(a) Before you install or modify a production safety system, you must submit a production safety system application to the District Manager for approval. The application must include the information prescribed in the following table:
(b) In the production safety system application, you must also certify the following:
(1) That all electrical installations were designed according to API RP 14F or API RP 14FZ, as applicable (incorporated by reference as specified in § 250.198);
(2) That the designs for the mechanical and electrical systems under paragraph (a) of this section were reviewed, approved, and stamped by an appropriate registered professional engineer(s). The registered professional engineer must be registered in a State or Territory of the United States and have sufficient expertise and experience to perform the duties; and
(3) That a hazards analysis was performed in accordance with § 250.1911 and API RP 14J (incorporated by reference as specified in § 250.198), and that you have a hazards analysis program in place to assess potential hazards during the operation of the facility.
(c) Before you begin production, you must certify, in a letter to the District Manager, that the mechanical and electrical systems were installed in accordance with the approved designs.
(d) Within 60 days after production commences, you must certify, in a letter to the District Manager, that the as-built diagrams for the new or modified production safety systems outlined in paragraphs (a)(1) and (2) of this section and the piping and instrumentation diagrams are on file and have been certified correct and stamped by an appropriate registered professional engineer(s). The registered professional engineer must be registered in a State or Territory in the United States and have sufficient expertise and experience to perform the duties.
(e) All as-built diagrams outlined in paragraphs (a)(1) and (2) of this section must be submitted to the District Manager within 60 days after production commences.
(f) You must maintain information concerning the approved designs and installation features of the production safety system at your offshore field office nearest the OCS facility or at other locations conveniently available to the District Manager. As-built piping and instrumentation diagrams must be maintained at a secure onshore location and readily available offshore. These documents must be made available to BSEE upon request and be retained for the life of the facility. All approvals are subject to field verifications.
You must comply with the production safety system requirements in §§ 250.851 through 250.872, in addition to the practices contained in API RP 14C (incorporated by reference as specified in § 250.198).
(a) Pressure vessels (including heat exchangers) and fired vessels supporting production operations must meet the requirements in the following table:
(b)
(c) Pressure shut-in sensors must be set according to the following table (initial set points for pressure sensors must be set utilizing gauge readings and engineering design):
(a) You must:
(1) Equip flowlines from wells with both PSH and PSL sensors. You must locate these sensors in accordance with section A.1 of API RP 14C (incorporated by reference as specified in § 250.198).
(2) Use pressure recording devices to establish the new operating pressure ranges of flowlines at any time when the normalized system pressure changes by 50 psig or 5 percent, whichever is higher. The pressure recording devices must document the pressure range over time intervals that are no less than 4 hours and no more than 30 days long.
(3) Maintain the most recent pressure recording information you used to determine operating pressure ranges at your field office nearest the OCS facility or at another location conveniently available to the District Manager for as long as the information is valid.
(b) Flowline shut-in sensors must meet the requirements in the following table (initial set points for pressure sensors must be set using gauge readings and engineering design):
(c) If a well flows directly to a pipeline before separation, the flowline and valves from the well located upstream of and including the header inlet valve(s) must have a working pressure equal to or greater than the maximum shut-in pressure of the well unless the flowline is protected by one of the following:
(1) A relief valve which vents into the platform flare scrubber or some other location approved by the District Manager. You must design the platform flare scrubber to handle, without liquid-hydrocarbon carryover to the flare, the maximum-anticipated flow of hydrocarbons that may be relieved to the vessel; or
(2) Two SSVs with independent PSH sensors connected to separate relays and sensing points and installed with adequate volume upstream of any block valve to allow sufficient time for the SSVs to close before exceeding the maximum allowable working pressure. Each independent PSH sensor must close both SSVs along with any associated flowline PSL sensor. If the maximum shut-in pressure of a dry tree satellite well(s) is greater than 1
(d) If a well flows directly to the pipeline from a header without prior separation, the header, the header inlet valves, and pipeline isolation valve must have a working pressure equal to or greater than the maximum shut-in pressure of the well unless the header is protected by the safety devices as outlined in paragraph (c) of this section.
(e) If you are installing flowlines constructed of unbonded flexible pipe on a floating platform, you must:
(1) Review the manufacturer's Design Methodology Verification Report and the independent verification agent's (IVA's) certificate for the design methodology contained in that report to ensure that the manufacturer has complied with the requirements of API Spec. 17J (incorporated by reference as specified in § 250.198);
(2) Determine that the unbonded flexible pipe is suitable for its intended purpose;
(3) Submit to the District Manager the manufacturer's design specifications for the unbonded flexible pipe; and
(4) Submit to the District Manager a statement certifying that the pipe is suitable for its intended use and that the manufacturer has complied with the IVA requirements of API Spec. 17J (incorporated by reference as specified in § 250.198).
(f) Automatic pressure or flow regulating choking devices must not prevent the normal functionality of the process safety system that includes, but is not limited to, the flowline pressure safety devices and the SSV.
(g) You may install a single flow safety valve (FSV) on the platform to protect multiple subsea pipelines or wells that tie into a single pipeline riser provided that you install an FSV for each riser on the platform and test it in accordance with the criteria prescribed in § 250.880(c)(2)(v).
(h) You may install a single PSHL sensor on the platform to protect multiple subsea pipelines that tie into a single pipeline riser provided that you install a PSHL sensor for each riser on the platform and locate it upstream of the BSDV.
You must ensure that:
(a) All shutdown devices, valves, and pressure sensors function in a manual reset mode;
(b) Sensors with integral automatic reset are equipped with an appropriate device to override the automatic reset mode; and
(c) All pressure sensors are equipped to permit testing with an external pressure source.
(a) For floating production units equipped with an auto slew system, you must integrate the auto slew control system with your process safety system allowing for automatic shut-in of the production process, including the sources (subsea wells, subsea pumps,
(1) Your buoy is clamped,
(2) Your auto slew mode is activated, and
(3) You encounter a ship heading/position failure or an exceedance of the rotational tolerances of the clamped buoy.
(b) For floating production units equipped with swivel stack arrangements, you must equip the portion of the swivel stack containing hydrocarbons with a leak detection system. Your leak detection system must be tied into your production process surface safety system allowing for automatic shut-in of the system. Upon seal system failure and detection of a hydrocarbon leak, your surface safety system must immediately initiate a process system shut-in according to §§ 250.838 and 250.839.
The ESD system must conform to the requirements of Appendix C, section C1, of API RP 14C (incorporated by reference as specified in § 250.198), and the following:
(a) The manually operated ESD valve(s) must be quick-opening and non-restricted to enable the rapid actuation of the shutdown system. Electronic ESD stations must be wired as de-energize to trip circuits or as supervised circuits. Because of the key role of the ESD system in the platform safety system, all ESD components must be of high quality and corrosion resistant and stations must be uniquely identified. Only ESD stations at the boat landing may utilize a loop of breakable synthetic tubing in lieu of a valve or electric switch. This breakable loop is not required to be physically located on the boat landing, but must be accessible from a vessel adjacent to or attached to the facility.
(b) You must maintain a schematic of the ESD that indicates the control functions of all safety devices for the platforms on the platform, at your field office nearest the OCS facility, or at another location conveniently available to the District Manager, for the life of the facility.
(a)
(b)
(a) You must install a pressure relief system or an adequate vent on the glycol regenerator (reboiler) to prevent over pressurization. The discharge of the relief valve must be vented in a nonhazardous manner.
(b) You must install the FSV on the dry glycol inlet to the glycol contact tower as near as practical to the glycol contact tower.
(c) You must install the shutdown valve (SDV) on the wet glycol outlet from the glycol contact tower as near as practical to the glycol contact tower.
(a) You must equip compressor installations with the following protective equipment as required in API RP 14C, sections A.4 and A.8 (incorporated by reference as specified in § 250.198).
(1) A pressure safety high (PSH) sensor, a pressure safety low (PSL) sensor, a pressure safety valve (PSV), a level safety high (LSH) sensor, and a level safety low (LSL) sensor to protect each interstage and suction scrubber.
(2) A temperature safety high (TSH) sensor in the discharge piping of each compressor cylinder or case discharge.
(3) You must design the PSH and PSL sensors and LSH controls protecting compressor suction and interstage scrubbers to actuate automatic SDVs located in each compressor suction and fuel gas line so that the compressor unit and the associated vessels can be isolated from all input sources. All automatic SDVs installed in compressor suction and fuel gas piping must also be actuated by the shutdown of the prime mover. Unless otherwise approved by the District Manager, gas-well gas affected by the closure of the automatic SDV on the suction side of a compressor must be diverted to the pipeline, diverted to a flare or vent in accordance with §§ 250.1160 or 250.1161, or shut-in at the wellhead.
(4) You must install a blowdown valve on the discharge line of all compressor installations that are 1,000 horsepower (746 kilowatts) or greater.
(b) Once system pressure has stabilized, you must use pressure recording devices to establish the new operating pressure ranges for compressor discharge sensors whenever the normalized system pressure changes by 50 psig or 5 percent, whichever is higher. The pressure recording devices must document the pressure range over time intervals that are no less than 4 hours and no more than 30 days long. You must maintain the most recent pressure recording information that you used to determine operating pressure ranges at your field office nearest the OCS facility or at another location conveniently available to the District Manager.
(c) Pressure shut-in sensors must be set according to the following table (initial set points for pressure sensors must be set utilizing gauge readings and engineering design):
(a) On fixed facilities, to protect all areas where production-handling equipment is located, you must install firefighting systems that meet the requirements of this paragraph. You must install a firewater system consisting of rigid pipe with fire hose stations and/or fixed firewater monitors to protect all areas where production-handling equipment is located. Your firewater system must include installation of a fixed water spray system in enclosed well-bay areas where hydrocarbon vapors may accumulate.
(1) Your firewater system must conform to API RP 14G (incorporated by reference as specified in § 250.198).
(2) Fuel or power for firewater pump drivers must be available for at least 30 minutes of run time during a platform shut-in. If necessary, you must install an alternate fuel or power supply to provide for this pump operating time unless the District Manager has approved an alternate firefighting system. In addition:
(i) As of September 7, 2017, you must have equipped all new firewater pump drivers with automatic starting capabilities upon activation of the ESD, fusible loop, or other fire detection system.
(ii) For electric-driven firewater pump drivers, to provide for a potential loss of primary power, you must install an automatic transfer switch to cross over to an emergency power source in order to maintain at least 30 minutes of run time. The emergency power source must be reliable and have adequate capacity to carry the locked-rotor currents of the fire pump motor and accessory equipment.
(iii) You must route power cables or conduits with wires installed between the fire water pump drivers and the automatic transfer switch away from hazardous-classified locations that can cause flame impingement. Power cables or conduits with wires that connect to the fire water pump drivers must be capable of maintaining circuit integrity for not less than 30 minutes of flame impingement.
(3) You must post, in a prominent place on the facility, a diagram of the firefighting system showing the location of all firefighting equipment.
(4) For operations in subfreezing climates, you must furnish evidence to the District Manager that the firefighting system is suitable for those conditions.
(5) You must obtain approval from the District Manager before installing any firefighting system.
(6) All firefighting equipment located on a facility must be in good working order whether approved as the primary, secondary, or ancillary firefighting system.
(b) On floating facilities, to protect all areas where production-handling equipment is located, you must install a firewater system consisting of rigid pipe with fire hose stations and/or fixed firewater monitors. You must install a fixed water spray system in enclosed well-bay areas where hydrocarbon vapors may accumulate. Your firewater system must conform to the USCG requirements for firefighting systems on floating facilities.
(c) Except as provided in paragraph (c)(1) and (2) of this section, on fixed and floating facilities, if you are required to maintain a firewater system and the system becomes inoperable, you must shut-in your production operations while making the necessary repairs. For fixed facilities only, you may continue your production operations on a temporary basis while you make the necessary repairs, provided that:
(1) You request that the appropriate District Manager approve the use of a chemical firefighting system on a temporary basis (for a period up to 7 days) while you make the necessary repairs;
(2) If you are unable to complete repairs during the approved time period because of circumstances beyond your control, the District Manager may grant multiple extensions to your previously approved request to use a chemical firefighting system for periods up to 7 days each.
For fixed platforms:
(a) On minor unmanned platforms, you may use a U.S. Coast Guard type and size rating “B-II” portable dry chemical unit (with a minimum UL Rating (US) of 60-B:C) or a 30-pound portable dry chemical unit, in lieu of a water system, as long as you ensure that the unit is available on the platform when personnel are on board.
(1) A minor platform is a structure with zero to five completions and no more than one item of production processing equipment.
(2) An unmanned platform is one that is not attended 24 hours a day or one on which personnel are not quartered overnight.
(b) On major platforms and minor manned platforms, you may use a firefighting system using chemicals-only in lieu of a water-based system if the District Manager determines that the use of a chemical system provides equivalent fire-protection control and would not increase the risk to human safety.
(1) A major platform is a structure with either six or more completions or zero to five completions with more than one item of production processing equipment.
(2) A minor platform is a structure with zero to five completions and no more than one item of production processing equipment.
(3) A manned platform is one that is attended 24 hours a day or one on which personnel are quartered overnight.
(c) On major platforms and minor manned platforms, to obtain approval to use a chemical-only fire prevention and control system in lieu of a water system under paragraph (b) of this section, you must submit to the District Manager:
(1) A justification for asserting that the use of a chemical system provides equivalent fire-protection control. The justification must address fire prevention, fire protection, fire control, and firefighting on the platform; and
(2) A risk assessment demonstrating that a chemical-only system would not increase the risk to human safety. You must provide the following and any other important information in your risk assessment:
(d) On major or minor platforms, if BSEE has approved your request to use a chemical-only fire suppressant system in lieu of a water system under paragraphs (b) and (c) of this section, and if you make an insignificant change to your platform subsequent to that approval, you must document the change and maintain the documentation for the life of the facility at either the facility or nearest field office for BSEE review and/or inspection. Do not submit this documentation to the District Manager. However, if you make a significant change to your platform (
When you install foam firefighting systems as part of a firefighting system that protects production handling areas, you must:
(a) Annually conduct an inspection of the foam concentrates and their tanks or storage containers for evidence of excessive sludging or deterioration;
(b) Annually send samples of the foam concentrate to the manufacturer or authorized representative for quality condition testing. You must have the sample tested to determine the specific gravity, pH, percentage of water dilution, and solid content. Based on these results, the foam must be certified by an authorized representative of the manufacturer as suitable firefighting foam consistent with the original manufacturer's specifications. The certification document must be readily accessible for field inspection. In lieu of sampling and certification, you may choose to replace the total inventory of foam with suitable new stock;
(c) Ensure that the quantity of concentrate meets design requirements, and that tanks or containers are kept full, with space allowed for expansion.
For production processing areas only:
(a) You must install fire (flame, heat, or smoke) sensors in all enclosed classified areas. You must install gas sensors in all inadequately ventilated, enclosed classified areas.
(1) Adequate ventilation is defined as ventilation that is sufficient to prevent accumulation of significant quantities of vapor-air mixture in concentrations over 25 percent of the lower explosive limit. An acceptable method of providing adequate ventilation is one that provides a change of air volume each 5 minutes or 1 cubic foot of air-volume flow per minute per square foot of solid floor area, whichever is greater.
(2) Enclosed areas (
(3) A classified area is any area classified Class I, Group D, Division 1 or 2, following the guidelines of API RP 500 (incorporated by reference as specified in § 250.198), or any area classified Class I, Zone 0, Zone 1, or Zone 2, following the guidelines of API RP 505 (incorporated by reference as specified in § 250.198).
(b) All detection systems must be capable of continuous monitoring. Fire-detection systems and portions of combustible gas-detection systems related to the higher gas-concentration levels must be of the manual-reset type. Combustible gas-detection systems related to the lower gas-concentration level may be of the automatic-reset type.
(c) A fuel-gas odorant or an automatic gas-detection and alarm system is required in enclosed, continuously manned areas of the facility which are provided with fuel gas. A gas detection system is not required for living quarters and doghouses that do not contain a gas source and that are not located in a classified area.
(d) The District Manager may require the installation and maintenance of a gas detector or alarm in any potentially hazardous area.
(e) Fire- and gas-detection systems must be an approved type, and designed and installed in accordance with API RP 14C, API RP 14G, API RP 14F, API RP 14FZ, API RP 500, and API RP 505 (all incorporated by reference as specified in § 250.198), provided that, if compliance with any provision of those standards would be in conflict with applicable regulations of the U.S. Coast Guard, compliance with the U.S. Coast Guard regulations controls.
You must design, install, and maintain electrical equipment and systems in accordance with the requirements in § 250.114.
You must have a program of erosion control in effect for wells or fields that have a history of sand production. The erosion-control program may include sand probes, X-ray, ultrasonic, or other satisfactory monitoring methods. You must maintain records for each lease that indicate the wells that have erosion-control programs in effect. You must also maintain the results of the programs for at least 2 years and make them available to BSEE upon request.
(a) You must equip pump installations with the protective equipment required in API RP 14C, Appendix A—A.7, Pumps (incorporated by reference as specified in § 250.198).
(b) You must use pressure recording devices to establish the new operating pressure ranges for pump discharge sensors at any time when the normalized system pressure changes by 50 psig or 5 percent, whichever is higher. Once system pressure has stabilized, pressure recording devices must be utilized to establish the new operating pressure ranges. The pressure recording devices must document the pressure range over time intervals that are no less than 4 hours and no more than 30 days long. You must only maintain the most recent pressure recording information that you used to determine operating pressure ranges at your field office nearest the OCS facility or at another location conveniently available to the District Manager.
(c) Pressure shut-in sensors must be set according to the following table (initial set points for pressure sensors must be set utilizing gauge readings and engineering design):
(d) The PSL must be placed into service when the pump discharge pressure has risen above the PSL sensing point, or within 45 seconds of the pump coming into service, whichever is sooner.
(e) You may exclude the PSH and PSL sensors on small, low-volume pumps such as chemical injection-type pumps. This is acceptable if such a pump is used as a sump pump or transfer pump, has a discharge rating of less than
(f) You must install a TSE in the immediate vicinity of all pumps in hydrocarbon service or those powered by platform fuel gas.
(g) The pump maximum discharge pressure must be determined using the maximum possible suction pressure and the maximum power output of the driver as appropriate for the pump type and service.
You must maintain all personnel safety equipment located on a facility, whether required or not, in good working condition.
(a) The District Manager must approve all temporary quarters to be installed in production processing areas or other classified areas on OCS facilities. You must equip such temporary quarters with all safety devices required by API RP 14C, Appendix C (incorporated by reference as specified in § 250.198).
(b) The District Manager may require you to install a temporary firewater system for temporary quarters in production processing areas or other classified areas.
(c) Temporary equipment associated with the production process system, including equipment used for well testing and/or well clean-up, must be approved by the District Manager.
On fixed OCS facilities, you may use non-metallic piping (such as that made from polyvinyl chloride, chlorinated polyvinyl chloride, and reinforced fiberglass) only in accordance with the requirements of § 250.841(b).
(a) Surface or subsurface safety devices must not be bypassed or blocked out of service unless they are temporarily out of service for startup, maintenance, or testing. You may take only the minimum number of safety devices out of service. Personnel must monitor the bypassed or blocked-out functions until the safety devices are placed back in service. Any surface or subsurface safety device which is temporarily out of service must be flagged. A designated visual indicator must be used to identify the bypassed safety device. You must follow the monitoring procedures as follows:
(1) If you are using a non-computer-based system, meaning your safety system operates primarily with pneumatic supply or non-programmable electrical systems, you must monitor bypassed safety devices by positioning monitoring personnel at either the control panel for the bypassed safety device, or at the bypassed safety device, or at the component that the bypassed safety device would be monitoring when in service. You must also ensure that monitoring personnel are able to view all relevant essential operating conditions until all bypassed safety devices are placed back in service and are able to initiate shut-in action in the event of an abnormal condition.
(2) If you are using a computer-based technology system, meaning a computer-controlled electronic safety system such as supervisory control and data acquisition and remote terminal units, you must monitor bypassed safety devices by maintaining instantaneous communications at all times among remote monitoring personnel and the personnel performing maintenance, testing, or startup. Until all bypassed safety devices are placed back in service, you must also position monitoring personnel at a designated control station that is capable of the following:
(i) Displaying all relevant essential operating conditions that affect the bypassed safety device, well, pipeline, and process component. If electronic display of all relevant essential conditions is not possible, you must have field personnel monitoring the level gauges (sight glass) and pressure gauges in order to know the current operating conditions. You must be in communication with all field personnel monitoring the gauges;
(ii) Controlling the production process equipment and the entire safety system;
(iii) Displaying a visual indicator when safety devices are placed in the bypassed mode; and
(iv) Upon command, overriding the bypassed safety device and initiating shut-in action in the event of an abnormal condition.
(3) You must not bypass for startup any element of the emergency support system or other support system required by API RP 14C, Appendix C (incorporated by reference as specified in § 250.198) without first receiving BSEE approval to depart from this
(i) The ESD system to provide a method to manually initiate platform shutdown by personnel observing abnormal conditions or undesirable events. You do not have to receive approval from the District Manager for manual reset and/or initial charging of the system;
(ii) The fire loop system to sense the heat of a fire and initiate platform shutdown, and other fire detection devices (flame, thermal, and smoke) that are used to enhance fire detection capability. You do not have to receive approval from the District Manager for manual reset and/or initial charging of the system;
(iii) The combustible gas detection system to sense the presence of hydrocarbons and initiate alarms and platform shutdown before gas concentrations reach the lower explosive limit;
(iv) Adequate ventilation;
(v) The containment system to collect escaped liquid hydrocarbons and initiate platform shutdown;
(vi) Subsurface safety valves, including those that are self-actuated (subsurface-controlled SSSVs) or those that are activated by an ESD system and/or a fire loop (surface-controlled SSSV). You do not have to receive approval from the District Manager for routine operations in accordance with § 250.817;
(vii) The pneumatic supply system; and
(viii) The system for discharging gas to the atmosphere.
(4) In instances where components of the ESD, as listed in paragraph (a)(3) of this section, are bypassed for maintenance, precautions must be taken to provide the equivalent level of protection that existed prior to the bypass.
(b) When wells are disconnected from producing facilities and blind flanged, or equipped with a tubing plug, or the master valves have been locked closed, you are not required to comply with the provisions of API RP 14C (incorporated by reference as specified in § 250.198) or this regulation concerning the following:
(1) Automatic fail-close SSVs on wellhead assemblies, and
(2) The PSH and PSL sensors in flowlines from wells.
(c) When pressure or atmospheric vessels are isolated from production facilities (
(d) All open-ended lines connected to producing facilities and wells must be plugged or blind-flanged, except those lines designed to be open-ended such as flare or vent lines.
(e) On all new production safety system installations, component process control devices and component safety devices must not be installed utilizing the same sensing points.
(f) All pneumatic control panels and computer based control stations must be labeled according to API RP 14C nomenclature.
(a) You may apply any or all of the industry standard Class B, Class C, or Class B/C logic to all applicable PSL sensors installed on process equipment, as long as the time delay does not exceed 45 seconds. Use of a PSL sensor with a time delay greater than 45 seconds requires BSEE approval in accordance with § 250.141. You must document on your field test records any use of a PSL sensor with a time delay greater than 45 seconds. For purposes of this section, PSL sensors are categorized as follows:
(1) Class B safety devices have logic that allows for the PSL sensors to be bypassed for a fixed time period (typically less than 15 seconds, but not more than 45 seconds). Examples include sensors used in conjunction with the design of pump and compressor panels such as PSL sensors, lubricator no-flows, and high-water jacket temperature shutdowns.
(2) Class C safety devices have logic that allows for the PSL sensors to be bypassed until the component comes into full service (
(3) Class B/C safety devices have logic that allows for the PSL sensors to incorporate a combination of Class B and Class C circuitry. These devices are used to ensure that the PSL sensors are not unnecessarily bypassed during startup and idle operations, (
(i) The Class B timer expires no later than 45 seconds from start activation, or
(ii) The Class C bypass is initiated until the pump builds up pressure above the PSL sensor set point and the PSL sensor comes into full service.
(b) If you do not install time delay circuitry that bypasses activation of PSL sensor shutdown logic for a specified time period on process and product transport equipment during startup and idle operations, you must manually bypass (pin out or disengage) the PSL sensor, with a time delay not to exceed 45 seconds.
All welding, burning, and hot-tapping activities must be conducted according to the specific requirements in § 250.113.
(a) You must equip atmospheric vessels used to process and/or store liquid hydrocarbons or other Class I liquids as described in API RP 500 or 505 (both incorporated by reference as specified in § 250.198) with protective equipment identified in API RP 14C, section A.5 (incorporated by reference as specified in § 250.198). Transport tanks approved by the U.S. Department of Transportation, that are sealed and not connected via interconnected piping to the production process train and that are used only for storage of refined liquid hydrocarbons or Class I liquids, are not required to be equipped with the protective equipment identified in API RP 14C, section A.5.
(b) You must ensure that all atmospheric vessels are designed and maintained to ensure the proper working conditions for LSH sensors. The LSH sensor bridle must be designed to prevent different density fluids from impacting sensor functionality. For atmospheric vessels that have oil buckets, the LSH sensor must be installed to sense the level in the oil bucket.
(c) You must ensure that all flame arrestors are maintained to ensure proper design function (installation of a system to allow for ease of inspection should be considered).
If you choose to install a subsea gas lift system, you must design your system as approved in your DWOP or as follows:
(a) Design the gas lift supply pipeline in accordance with API RP 14C (incorporated by reference as specified in § 250.198) for the gas lift supply system located on the platform.
(b) Meet the applicable requirements in the following table:
(c) Follow the valve closure times and hydraulic bleed requirements according to your approved DWOP for the following:
(1) Electro-hydraulic control system with gas lift,
(2) Electro-hydraulic control system with gas lift with loss of communications,
(3) Direct-hydraulic control system with gas lift.
(d) Follow the gas lift system valve testing requirements according to the following table:
If you choose to install a subsea water injection system, your system must comply with your approved DWOP, which must meet the following minimum requirements:
(a) Adhere to the water injection requirements described in API RP 14C (incorporated by reference as specified in § 250.198) for the water injection equipment located on the platform. In accordance with § 250.830, either a surface-controlled SSSV or a water injection valve (WIV) that is self-activated and not controlled by emergency shut-down (ESD) or sensor activation must be installed in a subsea water injection well.
(b) Equip a water injection pipeline with a surface FSV and water injection shutdown valve (WISDV) on the surface facility.
(c) Install a PSHL sensor upstream (in-board) of the FSV and WISDV.
(d) Use subsea tree(s), wellhead(s), connector(s), and tree valves, and surface-controlled SSSV or WIV associated with a water injection system that are rated for the maximum anticipated injection pressure.
(e) Consider the effects of hydrogen sulfide (H2S) when designing your water flood system, as required by § 250.805.
(f) Follow the valve closure times and hydraulic bleed requirements according to your approved DWOP for the following:
(1) Electro-hydraulic control system with water injection,
(2) Electro-hydraulic control system with water injection with loss of communications, and
(3) Direct-hydraulic control system with water injection.
(g) Comply with the following injection valve testing requirements:
(1) You must test your injection valves as provided in the following table:
(2) If a designated USV on a water injection well fails the applicable test under § 250.880(c)(4)(ii), you must notify the appropriate District Manager and request approval to designate another API Spec 6A and API Spec. 6AV1 (both incorporated by reference as specified in § 250.198) certified subsea valve as your USV.
(3) If a USV on a water injection well fails the test and the surface-controlled SSSV or WIV cannot be tested as required under (g)(1)(ii) of this section because of low reservoir pressure, you must submit a request to the appropriate District Manager with an alternative plan that ensures subsea shutdown capabilities.
(h) If you experience a loss of communications during water injection operations, you must comply with the following:
(1) Notify the appropriate District Manager within 12 hours after detecting loss of communication; and
(2) Obtain approval from the appropriate District Manager to continue to inject during the loss of communication.
If you choose to install a subsea pump system, your system must comply with your approved DWOP, which must meet the following minimum requirements:
(a) Include the installation of an isolation valve at the inlet of your subsea pump module.
(b) Include a PSHL sensor upstream of the BSDV, if the maximum possible discharge pressure of the subsea pump operating in a dead head condition (that is the maximum shut-in tubing pressure at the pump inlet and a closed BSDV) is less than the MAOP of the associated pipeline.
(c) If the maximum possible discharge pressure of the subsea pump operating in a dead head situation could be greater than the MAOP of the pipeline:
(1) Include, at minimum, 2 independent functioning PSHL sensors upstream of the subsea pump and 2 independent functioning PSHL sensors downstream of the pump, that:
(i) Are operational when the subsea pump is in service; and
(ii) Will, when activated, shut down the subsea pump, the subsea inlet isolation valve, and either the designated USV1, the USV2, or the alternate isolation valve.
(iii) If more than 2 PSHL sensors are installed both upstream and downstream of the subsea pump for operational flexibility, then 2 out of 3 voting logic may be implemented in which the subsea pump remains operational provided a minimum of 2 independent PSHL sensors are functional both upstream and downstream of the pump.
(2) Interlock the subsea pump motor with the BSDV to ensure that the pump cannot start or operate when the BSDV is closed, incorporate at a minimum the following permissive signals into the control system for your subsea pump, and ensure that the subsea pump is not able to be started or re-started unless:
(i) The BSDV is open;
(ii) All automated valves downstream of the subsea pump are open;
(iii) The upstream subsea pump isolation valve is open; and
(iv) All parameters associated with the subsea pump operation (
(3) Monitor the separator for seawater.
(4) Ensure that the subsea pump systems are controlled by an electro-hydraulic control system.
(d) Follow the valve closure times and hydraulic bleed requirements according to your approved DWOP for the following:
(1) Electro-hydraulic control system with a subsea pump;
(2) A loss of communication with the subsea well(s) and not a loss of communication with the subsea pump control system without an ESD or sensor activation;
(3) A loss of communication with the subsea pump control system, and not a loss of communication with the subsea well(s);
(4) A loss of communication with the subsea well(s) and the subsea pump control system.
(e) For subsea pump testing:
(1) Perform a complete subsea pump function test, including full shutdown, after any intervention or changes to the software and equipment affecting the subsea pump; and
(2) Test the subsea pump shutdown, including PSHL sensors both upstream and downstream of the pump, each quarter (not to exceed 120 days between tests). This testing may be performed concurrently with the ESD function test required by § 250.880(c)(4)(v).
No later than September 7, 2018, and at least once every 5 years thereafter, you must have a qualified third-party remove and inspect, and then you must repair or replace, as needed, the fire tube for tube-type heaters that are equipped with either automatically controlled natural or forced draft burners installed in either atmospheric or pressure vessels that heat hydrocarbons and/or glycol. If removal and inspection indicates tube-type heater deficiencies, you must complete and document repairs or replacements. You must document the inspection results, retain such documentation for at least 5 years, and make the documentation available to BSEE upon request.
(a)
(1) Notify the District Manager at least 72 hours before commencing production, so that BSEE may conduct a preproduction inspection of the integrated safety system.
(2) Notify the District Manager upon commencement of production so that BSEE may conduct a complete inspection.
(3) Notify the District Manager and receive BSEE approval before you perform any subsea intervention that modifies the existing subsea infrastructure in a way that may affect the casing monitoring capabilities and testing frequencies specified in the table set forth in paragraph (c)(4) of this section.
(b)
(1) Test safety valves and other equipment at the intervals specified in the tables set forth in paragraph (c) of this section or more frequently if operating conditions warrant; and
(2) Perform testing and inspections in accordance with API RP 14C, Appendix D (incorporated by reference as specified in § 250.198), and the additional requirements specified in the tables of this section or as approved in the DWOP for your subsea system.
(c)
(1) Comply with the following testing requirements for subsurface safety devices on dry tree wells:
(2) Comply with the following testing requirements for surface valves:
(3) Comply with the following testing requirements for surface safety systems and devices:
(4) Comply with the following testing requirements for subsurface safety devices and associated systems on subsea tree wells:
(d)
(2) Any subsea well that is completed and disconnected from monitoring capability for more than 6 months must meet the following testing and other requirements:
(i) Each well must have 3 pressure barriers:
(A) A closed and tested surface-controlled SSSV,
(B) A closed and tested USV, and
(C) One additional closed and tested tree valve.
(ii) For new completed wells, prior to the rig leaving the well, the pressure barriers must be tested as follows:
(A) The surface-controlled SSSV must be tested for leakage in accordance with § 250.828(c);
(B) The USV and other pressure barrier must be tested to confirm zero leakage rate.
(iii) A sealing pressure cap must be installed on the flowline connection hub until the flowline is installed and connected. The pressure cap must be designed to accommodate monitoring for pressure between the production wing valve and cap. The pressure cap must also be designed so that a remotely operated vehicle can bleed pressure off, monitor for buildup, and confirm barrier integrity.
(iv) Pressure monitoring at the sealing pressure cap on the flowline connection hub must be performed in each well at intervals not to exceed 12 months from the time of initial testing of the pressure barrier (prior to demobilizing the rig from the field).
(v) You must have a drilling vessel capable of intervention into the disconnected well in the field or readily accessible for use until the wells are brought on line.
(a) You must maintain records that show the present status and history of each safety device. Your records must include dates and details of installation, removal, inspection, testing, repairing, adjustments, and reinstallation.
(b) You must maintain these records for at least 2 years. You must maintain the records at your field office nearest the OCS facility and a secure onshore location. These records must be available for review by a representative of BSEE.
(c) You must submit to the appropriate District Manager a contact list for all OCS facilities at least annually or when contact information is revised. The contact list must include:
(1) Designated operator name;
(2) Designated primary point of contact for the facility;
(3) Facility phone number(s), if applicable;
(4) Facility fax number, if applicable;
(5) Facility radio frequency, if applicable;
(6) Facility helideck rating and size, if applicable; and
(7) Facility records location if not contained on the facility.
You must ensure that personnel installing, repairing, testing, maintaining, and operating surface and subsurface safety devices, and personnel operating production platforms (including, but not limited to, separation, dehydration, compression, sweetening, and metering operations), are trained in accordance with the procedures in subpart O and subpart S of this part.
National Highway Traffic Safety Administration (NHTSA) and Federal Motor Carrier Safety Administration (FMCSA), Department of Transportation (DOT).
Notice of Proposed Rulemaking (NPRM).
NHTSA and FMCSA are proposing regulations that would require vehicles with a gross vehicle weight rating of more than 11,793.4 kilograms (26,000 pounds) to be equipped with a speed limiting device initially set to a speed no greater than a speed to be specified in a final rule and would require motor carriers operating such vehicles in interstate commerce to maintain functional speed limiting devices set to a speed no greater than a speed to be specified in the final rule for the service life of the vehicle.
Specifically, NHTSA is proposing to establish a new Federal motor vehicle safety standard (FMVSS) requiring that each new multipurpose passenger vehicle, truck, bus and school bus with a gross vehicle weight rating (GVWR) of more than 11,793.4 kilograms (26,000 pounds) be equipped with a speed limiting device. The proposed FMVSS would also require each vehicle, as manufactured and sold, to have its device set to a speed not greater than a specified speed and to be equipped with means of reading the vehicle's current speed setting and the two previous speed settings (including the time and date the settings were changed) through its On-Board Diagnostic connection.
FMCSA is proposing a complementary Federal motor carrier safety regulation (FMCSR) requiring each commercial motor vehicle (CMV) with a GVWR of more than 11,793.4 kilograms (26,000 pounds) to be equipped with a speed limiting device meeting the requirements of the proposed FMVSS applicable to the vehicle at the time of manufacture, including the requirement that the device be set to a speed not greater than a specified speed. Motor carriers operating such vehicles in interstate commerce would be required to maintain the speed limiting devices for the service life of the vehicle.
Based on the agencies' review of the available data, limiting the speed of these heavy vehicles would reduce the severity of crashes involving these vehicles and reduce the resulting fatalities and injuries. We expect that, as a result of this joint rulemaking, virtually all of these vehicles would be limited to that speed.
You should submit your comments early enough to ensure that the docket receives them not later than November 7, 2016.
You may submit comments, identified by one or both of the docket numbers in the heading of this document, by any of the following methods:
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Studies examining the relationship between travel speed and crash severity have confirmed the common-sense conclusion that the severity of a crash increases with increased travel speed.
All vehicles with electronic engine control units (ECUs) are generally electronically speed governed to prevent engine or other damage to the vehicle. This is because the ECU monitors an engine's RPM (from which vehicle speed can be calculated) and also controls the supply of fuel to the engine. The information NHTSA has analyzed indicates that ECUs have been installed in most heavy trucks since 1999, although we are aware that some manufacturers were still installing mechanical controls through 2003. We seek comment on when ECUs with speed limiting capabilities became widely used for the other heavy vehicles covered by this proposal, such as buses and school buses.
The Department of Transportation has previously examined the issue of mandatory speed limitation for CMVs. In 1991, NHTSA published a report titled “Commercial Motor Vehicle Speed Control Devices,”
Several factors have changed since the submission of the 1991 report, including the data on the target population, changes in the costs and technology of speed limiting devices, and the repeal of the national maximum speed limit law. These changes undermine the conclusions contained in the 1991 report and support our reexamination of this safety issue.
In 2006, NHTSA received a petition from the American Trucking Associations (ATA) to initiate a rulemaking to amend the Federal Motor Vehicle Safety Standards (FMVSS) to require vehicle manufacturers to limit the speed of trucks with a Gross Vehicle Weight Rating (GVWR) greater than 26,000 pounds to no more than 68 miles per hour (mph). Concurrently, the ATA petitioned the FMCSA to amend the Federal Motor Carrier Safety Regulations (FMCSR) to prohibit owners and operators from adjusting the speed limiting devices in affected vehicles above 68 mph. That same year, FMCSA received a petition from Road Safe America to initiate a rulemaking to amend the FMCSRs to require that all trucks manufactured after 1990 with a GVWR greater than 26,000 pounds be equipped with electronic speed limiting devices set at not more than 68 mph.
On January 26, 2007, NHTSA and FMCSA responded to these petitions in a joint Request for Comments notice in the
Using Fatality Analysis Reporting System (FARS) and National Automotive Sampling System General Estimates System (NASS GES) crash data over the 10-year period between 2004 and 2013, the agencies examined crashes involving heavy vehicles (
The agencies' analysis found that crashes involving heavy vehicles traveling faster are more deadly than crashes involving heavy vehicles traveling at lower speeds. Given this fact, NHTSA is proposing to require multipurpose passenger vehicles, trucks, buses and school buses, with a GVWR of more than 11,793.4 kilograms (26,000 pounds) to be equipped with a speed limiting device. As manufactured and sold, each of these vehicles would be required by NHTSA to have its device set to a speed not greater than a specified speed. NHTSA is proposing a lead time of three years from publication of a final rule for manufacturers to meet the proposed requirements.
FMCSA is proposing a complementary Federal Motor Carrier Safety Regulation (FMCSR) requiring multipurpose passenger vehicles, trucks, and buses and school buses with a GVWR of more than 11,793.4 kilograms (26,000 pounds) operating in interstate commerce to be equipped with a speed limiting device meeting the requirements of the proposed FMVSS applicable to the vehicle at the time of manufacture, including the requirement that the device be set to a speed not greater than the specified speed. Motor carriers operating such vehicles in interstate commerce would be required to maintain the speed limiting devices for the service life of the vehicle.
Vehicles with GVWRs above 26,000 pounds include multipurpose passenger vehicles, trucks, and buses and school buses and will be referred to as heavy vehicles within this notice. The purpose of this joint rulemaking is to reduce the severity of crashes involving these heavy vehicles and to reduce the number of resulting fatalities.
Since this NPRM would apply both to vehicle manufacturers and motor carriers that purchase and operate these vehicles, this joint rulemaking is based on the authority of both NHTSA and FMCSA.
NHTSA's legal authority for today's NPRM is the National Traffic and Motor Vehicle Safety Act (“Motor Vehicle Safety Act”).
FMCSA's portion of this NPRM is based on the authority of the Motor Carrier Act of 1935 (1935 Act) and the Motor Carrier Safety Act of 1984 (1984 Act), both as amended. The two acts are delegated to FMCSA by 49 CFR 1.87(i) and (f), respectively.
These legal authorities and the legal basis for the proposed FMCSR are discussed in more detail in Section II of this notice.
NHTSA is proposing that speed limiting device requirements apply to all multipurpose passenger vehicles, trucks and buses with a GVWR of more than 11,793.4 kg (26,000 pounds). NHTSA considered several factors in determining the GVWR threshold for the proposed FMVSS. These vehicles carry the heaviest loads, and small increases in their speed have larger effects on the force of impact in a crash. Additionally, many of these vehicles are regulated by FMCSA and its State partners, permitting the establishment of an FMCSR to ensure the enforcement of the speed limiting requirements throughout the life of the vehicles.
Although the petitions for rulemaking requested that NHTSA permit manufacturers to set the speed limiting device at any speed up to and including 68 mph, the agency has not proposed a specific set speed. In Section X of this document and in the Preliminary Regulatory Impact Analysis, Initial Regulatory Flexibility Analysis, and Draft Environmental Assessment accompanying this proposal, NHTSA has considered the benefits and costs of 60 mph, 65 mph, and 68 mph maximum set speeds.
The agencies estimate that limiting the speed of heavy vehicles to 60 mph would save 162 to 498 lives annually, limiting the speed of heavy vehicles to 65 mph would save 63 to 214 lives annually, and limiting the speed of heavy vehicles to 68 mph would save 27 to 96 lives annually. Although we believe that the 60 mph alternative would result in additional safety benefits, we are not able to quantify the 60 mph alternative with the same confidence as the 65 mph and 68 mph alternatives.
To determine compliance with the operational requirements for the speed limiting device (
In order to reduce additional potential costs to vehicle manufacturers, NHTSA is not proposing requirements to prevent tampering or restrict adjusting the speed setting as part of the proposed FMVSS. Instead, to deter tampering with a vehicle's speed limiting device or modification of the set speed above the specified maximum set speed after the vehicle is sold, the proposed FMVSS would be reinforced by the proposed FMCSR, which would require motor carriers to maintain the speed limiting devices at a set speed within the range permitted by the FMVSS. To assist FMCSA's enforcement officials with post-installation inspections and investigations to ensure compliance with the requirement to maintain the speed limiters, NHTSA is proposing to require that the vehicle set speed and the speed determination parameters be readable through the On-Board Diagnostic (OBD) connection.
In addition to the new vehicle requirements included in this proposal, NHTSA is considering whether to require commercial vehicles with a GVWR of more than 26,000 pounds currently on the road to be retrofitted with a speed limiting device with the speed set to no more than a specified speed. The agency has not included a retrofit requirement in this proposal because of concerns about the technical feasibility, cost, enforcement, and small business impacts of such a requirement. However, we are seeking public comment to improve our understanding of the real-world impact of implementing a speed limiting device retrofit requirement. As an alternative to a retrofit requirement, the agencies are also requesting comment on whether to extend the set speed requirement only
Based on our review of the available data, limiting the speed of heavy vehicles would reduce the severity of crashes involving these vehicles and reduce the resulting fatalities and injuries. Because virtually all heavy vehicles are CMVs and would be subject to both the proposed FMVSS and the proposed FMCSR, we expect that, as a result of this joint rulemaking, virtually all heavy vehicles would be speed limited.
The agencies project that this joint rulemaking would be cost-beneficial. Specifically, by reducing the severity of crashes involving heavy vehicles, we estimate that limiting heavy vehicles to 68 mph would save 27 to 96 lives annually, limiting heavy vehicles to 65 mph would save 63 to 214 lives annually, and limiting heavy vehicles to 60 mph would save 162 to 498 lives annually.
Additionally, we project that this joint rulemaking would result in fuel savings and greenhouse gas (GHG) emissions reductions totaling of $848 million annually, assuming a 7 percent discount for fuel and a 3 percent discount rate for GHG, for 60 mph and 65 mph speed limiter settings.
The cost of the proposed FMVSS to vehicle manufacturers is expected to be minimal. As discussed above, most vehicles to which the proposed FMVSS would apply are already equipped with electronic engine controls which include the capability to limit the speed of the vehicle, but may not have these controls turned on automatically.
In addition to the costs to vehicle manufacturers, we have evaluated the societal cost implications of these proposed rules. We estimate that the proposed rules would cost $1,561 million for 60 mph speed limiters, $523 million for 65 mph speed limiters, and $209 million for 68 mph speed limiters $433 million annually, assuming a 7 percent discount rate, as a result of the potentially lower travel speeds and delay in the delivery of goods. However, the estimated fuel savings benefits of this proposed rule exceed these estimated societal costs.
The commercial trucking market fits the classic definition of a negative externality, in which benefits are enjoyed by one party, but the costs associated with that benefit are imposed on another. In this case, higher travel speeds may produce more severe traffic crashes that result in more death, more injury, and greater property damage. While the cost of excess fuel consumption is borne by the vehicle fleet operators, the resulting fatalities, greenhouse gases, and pollutants may be imposed on society. The agencies estimate that this rule would be cost-beneficial. Even assuming that the proposed rule would result in the high cost estimate and the low benefit estimate, the net benefits of this rulemaking are estimated to be $1.1 billion to $5.0 billion annually for 60 mph speed limiters, $1.0 billion to $2.8 billion annually for 65 mph speed limiters, and $0.5 to $1.3 billion annually for 68 mph speed limiters, assuming a 7 percent discount rate.
The agencies seek comments and suggestions on any alternative options that would lower cost and maintain all or most of the benefits of the proposal, as well as information relative to a phase-in of the proposed requirements or alternatives to our proposed three-year lead time for manufacturers to meet the requirements of the new FMVSS.
Since this NPRM would apply both to vehicle manufacturers and motor carriers that purchase and operate these vehicles, this rulemaking is based on the authority of both NHTSA and FMCSA.
NHTSA's legal authority for today's NPRM is the National Traffic and Motor Vehicle Safety Act (“Motor Vehicle Safety Act”). Under 49 U.S.C. Chapter 301, Motor Vehicle Safety (49 U.S.C. 30101
Mandating speed limiting devices in heavy vehicles and requiring that those devices be set at speeds not greater than a maximum specified speed would meet the need for motor vehicle safety by reducing the severity of crashes involving heavy vehicles and reducing the number of fatalities and injuries that result from such crashes. These safety benefits are summarized above and discussed in more detail below in Section X. The proposed FMVSS would be practicable because the vehicles that would be subject to the requirements already have speed-limiting capability. The proposed FMVSS also contains objective performance criteria for evaluating the required speed limiting device, including a vehicle test procedure based on a United Nations Economic Commission for Europe (UNECE) test procedure, specification of the type of setting information that must be retrievable (
FMCSA's portion of this NPRM is based on the authority of the Motor Carrier Act of 1935 (1935 Act) and the Motor Carrier Safety Act of 1984 (1984 Act), both as amended. The two acts are delegated to FMCSA by 49 CFR 1.87(i) and (f), respectively.
The 1935 Act authorizes the Department of Transportation (DOT) to “prescribe requirements for — (1) qualifications and maximum hours of service of employees of, and safety of operation and equipment of, a motor carrier; and (2) qualifications and maximum hours of service of employees of, and standards of equipment of, a motor private carrier, when needed to promote safety of operations” [49 U.S.C. 31502(b)].
The 1984 Act confers on DOT authority to regulate drivers, motor carriers, and vehicle equipment. “At a minimum, the regulations shall ensure that—(1) commercial motor vehicles are maintained, equipped, loaded, and operated safely; (2) the responsibilities imposed on operators of commercial motor vehicles do not impair their ability to operate the vehicles safely; (3) the physical condition of operators of commercial motor vehicles is adequate to enable them to operate the vehicles safely . . . ; and (4) the operation of commercial motor vehicles does not have a deleterious effect on the physical condition of the operators” [49 U.S.C. 31136(a)(1)-(4)]. Sec. 32911 of the Moving Ahead for Progress in the 21st Century Act (MAP-21) [Pub. L. 112-141, 126 Stat. 405, July 6, 2012] enacted a fifth requirement,
The 1935 Act authorizes regulations on the “safety of operations and equipment” of a for-hire carrier and “standards of equipment” of a private carrier, “when needed to promote safety” [49 U.S.C. 31502(b)(1)-(2)]. Speed limiting devices constitute safety equipment, as the preamble of this proposed rule amply demonstrates, and the 1935 Act therefore authorizes FMCSA to require that such equipment be maintained as long as the vehicle is in service.
Because NHTSA is proposing to require vehicle manufacturers to equip every new multipurpose passenger vehicle, truck, and bus with a gross
The proposed rule does not directly address § 31136(a)(3), dealing with the physical condition of the driver, or § 31136(a)(4), concerning the effect of driving on the physical condition of operators. However, the proposed rule would significantly reduce the consumption of diesel fuel (which is used by most vehicles heavier than 26,000 pounds), with corresponding reductions in exhaust emissions. The effect on the health of drivers (and others) from exposure to diesel exhaust is difficult to estimate in the absence of a dose/response curve, significant changes in the chemical composition of diesel fuel over the years, and the presence of confounding factors like smoking [
Finally, consistent with § 31136(a)(5), a working speed limiting device will make it more difficult for a “motor carrier, shipper, receiver, or transportation intermediary” to coerce a driver to exceed highway speed limits in violation of the regulatory requirements of 49 CFR 392.2 and 392.6.
The 1984 Act confers jurisdiction over “commercial motor vehicles” (CMVs) operating in interstate commerce. The term CMV includes 4 alternative definitions: A minimum weight of 10,001 pounds gross vehicle weight (GVW) or GVWR, whichever is greater [49 U.S.C. 31132(1)(A)]; two different capacity thresholds for different types of passenger vehicle operation [§ 31132(1)(B)-(C)]; or the transportation of placardable quantities of hazardous material [§ 31132(1)(D)]. NHTSA proposes to require manufacturers to install speed limiting devices only on vehicles with a GVWR above 26,000 pounds. FMCSA has no authority to regulate vehicle manufacturers [49 U.S.C. 31147(b)] but proposes to require operators of CMVs covered by the NHTSA requirement who use the vehicles in interstate commerce to maintain speed limiting devices at the same level of effectiveness as the original equipment, irrespective of the CMV's passenger capacity or use to transport placardable quantities of hazardous material.
Before prescribing any regulations, FMCSA must also consider their “costs and benefits” [49 U.S.C. 31136(c)(2)(A) and 31502(d)]. Those factors are discussed in this proposed rule.
All vehicles with electronic engine control units (ECUs) are electronically speed limited to prevent general damage to the vehicle. This is because the ECU monitors an engine's RPM and also controls the supply of fuel to the engine. Available information indicates that ECUs have been installed in most heavy trucks since 1999, though we are aware that some manufacturers were still installing mechanical controls through 2003.
Section 9108 of the Truck and Bus Safety and Regulatory Reform Act of 1988 required the Secretary of Transportation to conduct a study on whether devices that control the speed of CMVs enhance safe operation of such vehicles and to submit to Congress a report on the results of the study together with recommendations on whether to make the use of speed control devices mandatory for CMVs.
In response to this Act, NHTSA published a Report to Congress titled “Commercial Motor Vehicle Speed Control Safety.”
The report described the results of non-detectable radar studies that showed that highway speed limit compliance by combination trucks was poor but better than that of passenger vehicles. In the non-detectable radar studies examined in the report, most trucks that were found to be speeding were traveling at just over the posted speed limit. Crash statistics indicated that speeding was generally less associated with combination truck crashes than it was with passenger vehicle crashes. The report described devices available to control truck speed and ways that they were applied in commercial fleet settings. The report was supportive of fleet applications of speed monitoring devices and speed limiting devices but at that time concluded that there was not sufficient justification to consider requiring all heavy trucks to be so equipped due to the small number of target crashes and uncertainties regarding the potential for crash reduction, which suggested that the benefits of mandatory speed limitation were questionable. Specifically, problem size statistics
On October 20, 2006, the ATA submitted a petition to NHTSA, pursuant to 49 CFR 552.3, to initiate a rulemaking to amend the FMVSS to require vehicle manufacturers to limit the speed of trucks with a GVWR greater than 26,000 pounds to no more than 68 mph.
The ATA stated that reducing speed-related crashes involving trucks is critical to the safety mission of both NHTSA and FMCSA, and that the requested requirements are necessary in order to reduce the number and severity of crashes involving large trucks. ATA's petition stated:
A lack of focus on speed as a causal or significant contributing factor in crashes involving large trucks represents a significant gap in the federal government's truck safety strategy. While much of the federal truck safety budget has focused on ensuring the safe condition of equipment, on driver fatigue, and on prevention of impaired driving, it is clear from the research that speeding is a more significant factor in crashes involving trucks than any of the factors that currently receive the largest proportion of agency attention and resources.
ATA analyzed five years of fatal truck-involved crash data. We found that in 20 percent of truck-involved fatal crashes where speeding on the part of the truck driver was cited as a factor in the crash, and the truck's speed was recorded, the speed of the truck exceeded 68 mph. However, because the truck's speed is reported by investigating officers in only about half of truck-involved fatal crashes, it is impossible to determine the actual number of potential crashes that might be avoided by limiting top truck speed to 68 mph. However, reasonable assumptions can be made and ATA believes the number of fatal crashes that could be avoided is significant.
The ATA stated in its petition that reducing the speed of trucks will likely reduce both the number and severity of crashes, although ATA did not quantify injury or fatality reduction benefits. The ATA also stated that the reduced number of crashes, resulting from the lower speed for trucks, will reduce congestion, thereby reducing societal costs associated with the loss of productivity that occurs when vehicles have been disabled in a crash or delayed at a crash site.
According to the ATA, there will be little or no cost increase for truck and truck tractor manufacturers associated with limiting the maximum speed since speed limiting devices are already installed on these vehicles during manufacture as a feature of the electronic engine control unit. Also, the ATA contended that the cost to carriers for the increase in time required to complete a delivery will be offset by savings in fuel consumption, fewer crashes, and less equipment wear.
On September 8, 2006, Road Safe America, a public safety interest group, and a group of nine motor carriers
On January 26, 2007, NHTSA and FMCSA published a joint Request for Comments notice in the
The Agencies received over 3,000 comments in response to the Request for Comments, mostly from private citizens and small businesses.
Comments from private citizens and small organizations supporting the petitions include responses from individuals who were involved in crashes with heavy trucks or had friends or relatives who were killed or severely injured in crashes with large trucks. The private citizen supporters of the petitions include non-truck drivers who stated they are intimidated by the hazardous driving practices of some truck drivers, such as speeding, tailgating, and abrupt lane changes. These comments expressed the belief that limiting the speed of heavy trucks to 68 mph would result in safer highways, and several private citizens recommended that trucks be limited to 65 mph rather than 68 mph.
Trucking organizations and safety groups supported the petition for similar reasons, and the comments summarized below represent the range of issues they addressed.
Schneider National, Inc. (Schneider), a motor carrier with a sizeable trucking
J.B. Hunt Transport, Inc. (J. B. Hunt), another large trucking fleet, commented that a differential speed between cars and large trucks will result from trucks being equipped with speed limiting devices set below the posted speed limit. This speed differential may cause a safety hazard; however, J.B. Hunt believes that the current safety hazard caused by large trucks traveling at speeds in excess of posted limits is of greater concern.
Advocates for Highway and Auto Safety (Advocates) commented that large trucks require 20 to 40 percent more braking distance than passenger cars and light trucks for a given travel speed. Advocates also indicated that it did not believe that the data in the agency's 1991 Report to Congress are still valid because the speed limits posted by the States over the past ten years are much higher than the national posted speed limit of 65 mph that was in effect in 1991.
The Insurance Institute for Highway Safety (IIHS) stated on-board electronic ECUs will maintain the desired speed control for vehicles when enforcement efforts are not sufficient due to lack of resources. IIHS stated that there is already widespread use of speed governors by carriers and a mandate will result in net safety and economic benefits. IIHS asserted that limiting trucks to 68 mph would enhance safety but that limiting the vehicles to speeds below 68 mph would be safer.
The Governors Highway Safety Association (GHSA) commented that large trucks are over-represented in motor vehicle crashes, stating that, based on 2004 data, large trucks were 3 percent of registered vehicles and represented about 8 percent of the total miles traveled nationwide, but were involved in 12 percent of traffic fatalities. GHSA stated that conventional approaches to vehicle speed control do not provide optimal benefits because of limited enforcement resources and the large number of miles of highway to cover. Accordingly, GHSA stated that it is prudent to consider requiring speed-limiting devices since they are currently installed in large trucks and can be adapted to be tamper-resistant.
Several comments, including those from ATA's Technology & Maintenance Council, provided information concerning economic, non-safety benefits that would result from requiring large trucks to be speed limited. The Technology & Maintenance Council stated that an increase of 1 mph results in a 0.1 mpg increase in fuel consumption, and for every 1 mph increase in speed over 55 mph, there is a reduction of 1 percent in tire tread life.
Comments opposing the petitions were received from many independent truck drivers, the Owner-Operator Independent Drivers Association (OOIDA), the Truckload Carriers Association (TCA), and private citizens (non-truck drivers).
OOIDA asserted that mandating speed limiting devices would not reduce the number of crashes involving heavy trucks. Specifically, OOIDA commented that the agency's 1991 Report to Congress is still valid today—asserting there is no need to mandate speed limiting devices because the target population (high speed crashes) is still small compared to the total number of truck crashes. According to OOIDA, speed limiting devices would not have an effect on crashes in areas where the posted speed limit for trucks is 65 mph or below. OOIDA believes that the petitioners are attempting to force all trucks to be speed-limited so that the major trucking companies with speed-limited vehicles will not be forced to compete for drivers against independent trucking operations that have not limited their speeds to 68 mph or below. OOIDA also questioned the magnitude of the fuel economy benefits that would be realized with speed limiting devices and stated that it is not necessary to set large truck speed limiting devices at 68 mph to realize most of the economic benefits cited by the petitioners, because improved fuel economy and reduced emissions can be achieved with improved truck designs. OOIDA also stated that driver compensation and the lack of entry level driver training contribute to the problem of driving at excessive speeds.
TCA and OOIDA both commented that a speed differential will be created in many states by the 68 mph speed limit for heavy trucks and a higher speed limit for other vehicles. This speed differential could result in more interaction between cars and trucks, thus posing an additional safety risk for cars and trucks.
According to comments from CDW Transport, a trucking fleet, speed limiting devices should be required on passenger vehicles as well as CMVs.
Several comments from private citizens and small businesses opposed to the petitions stated that speed is not the only cause of crashes—that weather and highway conditions are also significant factors. There were some comments stating that passenger vehicles cause the majority of the crashes between trucks and passenger vehicles. Some commenters stated that truck drivers will experience more fatigue with a 68-mph maximum speed, which could result in more crashes. Others expressed the opinion that State and local law enforcement agencies should enforce the speed of all vehicles on the nation's roads and highways, while some commenters favored a 75-mph limit for truck speed limiting devices, instead of 68 mph, to match the highest posted speed limit in the country.
The Truck and Engine Manufacturers Association (EMA)
On January 3, 2011, NHTSA published a notice granting the two speed limiting device-related petitions.
In March 2012, FMCSA published a research report on a study intended to identify the safety impacts of implementing speed limiting devices in commercial vehicle fleet operation.
FMCSA's Compliance, Safety, and Accountability Program
The FMCSA report focused on the effectiveness of a set speed limiter in avoiding crashes. Because this research relied on fleets to report crashes, a level of uncertainty was introduced based on varying reporting techniques. Additional uncertainty was introduced because of difficulties in establishing comparable routes in order to balance risk exposure. While the FMCSA study was large, the agencies are using a distinctively different approach for the estimation of benefits that includes 10 years of crash data analysis. As described later in this notice, NHTSA has examined actual crashes and the severity of those crashes at various speeds to estimate the safety benefits of reducing crash speeds. While NHTSA's approach to estimating the safety benefits is more conservative, the agency has greater confidence that the benefits demonstrated in our approach will be fully realized because of our approach's ability to more effectively isolate the effects of speed reduction on safety.
Studies examining the relationship between travel speed and crash severity have concluded that the severity of a crash increases with increased travel speed.
In evaluating the role travel speed plays in heavy vehicle crashes, the agencies used FARS and GES crash data over the 10-year period between 2004 and 2013 to examine crashes involving heavy vehicles (
Among the 10,440 fatalities, 9,747 resulted from crashes involving combination trucks, 442 resulted from crashes involving single unit trucks and the remaining 251 resulted from crashes involving buses.
In addition to examining the FARS and NASS GES data relating to fatal heavy vehicle crashes, the agencies reviewed the National Transportation Safety Board (NTSB) Accident Reports to better understand the details surrounding high-speed crashes involving motorcoaches. The agencies identified one motorcoach crash in which excessive vehicle speed was cited as a major safety risk. The crash occurred on U.S. Route 163, in Mexican Hat, Utah, on January 6, 2008.
As part of the crash investigation, NTSB conducted a vehicle speed analysis and estimated that the motorcoach was likely traveling 88 mph at the time of the crash. Although the motorcoach had a speed-limiting device with a maximum speed of 72 mph, NTSB determined that the motorcoach was capable of achieving a higher speed while in 10th gear when going downhill.
Based on the facts surrounding this crash, this incident does not necessarily demonstrate the safety risk that speed-limiting devices are meant to address. Existing speed-limiting devices regulate a vehicle's speed by monitoring the engine's RPM and controlling the supply of fuel to the engine, but do not limit the downhill speed of a vehicle. Although today's proposal would not necessarily limit speed on downhill portions of roadways, we are requesting comments on whether a device that could limit speeds in such a situation is technically feasible.
As discussed above, in 1991, NHTSA published a report titled “Commercial Motor Vehicle Speed Control Devices.”
In response to the two petitions received by NHTSA, we reexamined the report and determined that several factors have changed since its submission in 1991, including data on the target population, changes in the costs and technology of speed limiting devices, and the repeal of the national maximum speed limit law. These changes undermine the conclusions contained in the 1991 report.
The 1991 report focused on the crash involvement rate of heavy vehicles. The report estimated 39 fatalities annually involving combination trucks traveling in excess of 70 mph. However, the report stated that NHTSA was unable to determine whether the reduction in heavy vehicle travel speeds would actually reduce the crash risk (or resulting fatality risk) of these vehicles significantly, since other, non-speed-related factors might still have occurred to cause the crashes. The report determined that the incremental benefits of mandatory speed limiting devices were questionable.
As described in more detail below and in the Preliminary Regulatory Impact Analysis (PRIA) that accompanies this NPRM, included in the docket, the agencies have analyzed more recent data from 2004 to 2013 in order to determine the potential benefits of limiting the maximum speed of vehicles with a GVWR of over 11,793.4 kg (26,000 pounds). Instead of focusing on the effect of such devices on crash involvement rate, we have focused on their effect on crash severity and used this approach to isolate the effect of speed on the fatal crash rate. Accordingly, this methodology allows us to estimate with greater certainty the lives that can be saved by electronically setting the maximum speed of vehicles with a GVWR of over 11,793.4 kg (26,000 pounds). Additionally, the 1991 report detailed the mechanisms for limiting speed available at that time and their associated costs. While the report accurately predicted the proliferation of electronically-controlled engines capable of limiting speed, it also noted the high cost of installing mechanical engine speed governors on vehicles. The available information indicates that electronically-controlled engines have been installed in most heavy trucks since 1999, though we are aware that some manufacturers were still installing mechanical controls through 2003. Accordingly, many of the equipment cost concerns discussed in the 1991 report are inapplicable today.
Finally, during the time the 1991 report was being developed, the maximum speed limit in the U.S. was 55 mph.
Thus, vehicles, including those with a GVWR of 11,793.4 kg (26,000 pounds), are now traveling faster than they were in 1991.
Based on the foregoing, the agencies have determined that it was appropriate to reexamine the report to Congress and have come to the conclusion that the concerns and conclusions in that report are no longer valid. However, we have no plans at this time to prepare an updated study, given limited agency resources.
In developing this proposal, the agencies examined speed-limiting requirements in other countries, which are summarized below. Several jurisdictions have imposed speed-limiting requirements on certain heavy
Transport Canada does not have a Canadian Motor Vehicle Safety Standard for heavy vehicle speed limiting; however, the provinces of Ontario and Quebec do require that if a CMV is equipped with an electronic control module capable of being programmed to limit vehicle speed, it must be set to no more than 105 km/h (65 mph).
Additional requirements for Ontario include the following:
• A speed-limiting device is properly set if it prevents a driver, by means of accelerator application, from accelerating to or maintaining a speed greater than permitted.
• The maximum speed shall be set by means of the electronic control module that limits the feed of fuel to the engine.
• A CMV is exempt if it is equipped with an equally effective device, not dependent on the electronic control module, which allows limitation of vehicle speed, remotely or not, but does not allow the driver to deactivate or modify the set speed.
• All aspects of a CMV's computer device or devices, computer programs, components, equipment and connections that are capable of playing a role in preventing a driver from increasing the speed of a CMV beyond a specified value shall be in good working order.
• A CMV's electronic control module shall contain information that accurately corresponds with any component or feature of the vehicle referred to in the module, including information regarding the tire rolling radius, axle gear ratio and transmission gear ratio.
In Australia, heavy goods vehicles and heavy omnibus maximum road speed are regulated through the Australian Design Rule (ADR) 65/00 “Maximum Road Speed Limiting for Heavy Goods Vehicles.” This standard applies to heavy omnibuses with a gross vehicle mass (GVM) of 5 tons or more (UNECE category code M3), as well as heavy goods vehicles over 12 tons (UNECE category code N3). For “Road Train” vehicles, the maximum road speed capability is established by the State or Territory authority. For other heavy goods vehicles and for heavy omnibus vehicles, the maximum road speed capability may be no greater than 100 km/h (62 mph).
The ADR allows for vehicles to be speed-limited by means of gearing or a governor and tested with the following conditions:
• The tires shall be bedded and the pressure shall be as specified by the manufacturer.
• The vehicle shall be at ‘Unladen Mass.’
• The track surface shall be free from standing water, snow or ice and shall be free from uneven patches; and the gradient shall not exceed 2 percent and gradients shall not vary by more than 1 percent excluding camber effects.
• The mean wind road speed measured at a height at least 1 meter above the ground shall be less than 6 m/s with gusts not exceeding 10 m/s.
• The instantaneous vehicle road speed shall be recorded throughout the test with a road speed measurement accuracy of at least plus or minus 1 percent at maximum time intervals of 0.1 seconds. The test is then conducted “starting from a road speed 10 km/h less than the ‘Set Speed’ and the vehicle shall be accelerated as much as possible without changing gear by using a fully positive action on the accelerator control. This action shall be maintained without changing gear for at least 30 seconds after the ‘Set Speed’ is achieved.” The acceptance criteria for this test are twofold.
○ Within the first 10 seconds after reaching the ‘Set Speed’ the maximum vehicle road speed shall not exceed 105% of ‘Set Speed’ and the rate of change of vehicle road speed shall not exceed 0.5 m/s
○ More than 10 seconds after reaching the ‘Set Speed’, the maximum vehicle road speed shall not differ from the ‘Set Speed’ by more than plus or minus 3.3% of the ‘Set Speed’ and the rate of change of road speed shall not exceed 0.2 m/s
In 1992, the European Commission (EC) issued directive 92/6/EEC, requiring installation of speed limiting devices on trucks weighing over 12,000 kg (26,400 pounds) and buses with eight or more passenger seats weighing over 10,000 kg (22,000 pounds). The directive required that the speed limiting devices be set in such a way that covered trucks could not exceed 90 km/h (55.9 mph) and that covered buses could not exceed 100 km/h (62.1 mph). These requirements were phased in, initially applying to new vehicles registered after January 1, 1994. A retrofit requirement was subsequently added so that the speed-limiting requirements apply to all covered vehicles registered after January 1, 1988.
That same year, UNECE enacted Regulation 89 (ECE R89), which details uniform provisions concerning the approval of vehicles with regard to their maximum speed and installation of speed limiting devices, as well as approval of speed limiting devices themselves.
The ECE R89 test involves running the vehicle on a test track at a speed 10 km/h (6.2 mph) below the set speed and then accelerating the vehicle as much as possible until at least 30 seconds after the vehicle speed has stabilized. The speed of the vehicle is recorded at intervals of less than 0.1 second. The test is considered satisfactory if the stabilized speed of the vehicle does not exceed the set speed of the vehicle by more than five percent of the set speed or 5 km/h (3.1 mph) (whichever is greater), the maximum speed does not
In 2002, the EC issued directive 2002/85/EC, which extended the coverage of the speed limiting device requirements to include trucks weighing between 3,500 kg (7,716 pounds) and 12,000 kg (26,400 pounds) and buses with eight or more passenger seats weighing less than 10,000 kg (22,000 pounds).
The ECE R89 requirements are as follows:
• The speed limitation must be such that the vehicle in normal use, despite the vibrations to which it may be subjected, complies with certain provisions including the following:
○ The vehicle's speed limiting device (SLD) must be so designed, constructed and assembled as to resist corrosion and ageing phenomena to which it may be exposed and to resist tampering in accordance with the paragraph below.
The limitation threshold must not, in any case, be capable of being increased or removed temporarily or permanently on vehicles in use.
The speed limitation function and the connections necessary for its operation, except those essential for the running of the vehicle, shall be capable of being protected from any unauthorized adjustments or the interruption of its energy supply by the attachment of sealing devices and/or the need to use special tools.
○ The speed limiting function shall not actuate the vehicle's service braking device. A permanent brake (
○ The speed limitation function must be such that it does not affect the vehicle's road speed if a positive action on the accelerator is applied when the vehicle is running at its set speed.
○ The speed limitation function may allow normal acceleration control for the purpose of gear changing.
○ No malfunction or unauthorized interference shall result in an increase in engine power above that demanded by the position of the driver's accelerator.
○ The speed limitation function shall be obtained regardless of the accelerator control used if there is more than one such control which may be reached from the driver's seating position.
○ The speed limitation function shall operate satisfactorily in its electromagnetic environment “without unacceptable electromagnetic disturbance for anything in this environment.”
○ The applicant for approval shall provide documentation describing checking and calibration procedures. “It shall be possible to check the functioning of the speed limitation function whilst the vehicle is stationary.”
Annex 5 of the ECE R89 regulation provides specific vehicle, test track, test equipment, and test methods upon which we have based our proposed test procedure. The ECE regulation also contains specific acceleration, deceleration, and speed.
The test begins with the vehicle running at a speed 10 km/h below the set speed and then accelerated as much as possible using a fully positive action on the accelerator control. This action is then maintained for at least 30 seconds after the vehicle speed has been stabilized. During the test, the vehicle's precise speed and time are collected in order to calculate the maximum speed, stabilized speed, the amount of time required to stabilize the speed, maximum acceleration before the stabilized speed is established, and the maximum acceleration during the stabilized period.
In Japan, speed limitation devices are required to be installed on motor vehicles used to carry goods and have a GVWR of 8 tons or more or a maximum loading capacity of 5 tons or more. These devices are also required on trucks drawing trailers which have a GVWR of 8 tons or more or a maximum loading capacity of 5 tons or more. The general rules for these devices are as follows:
• The speed limitation device shall be so constructed that the vehicle may not be accelerated by the operation of the acceleration devices, such as the accelerator pedal, when the vehicle is running at its set speed.
• The set speed of the speed limitation device shall be any speed not exceeding 90 km/h. Furthermore, the speed limitation device shall be so constructed that the users, etc. of the vehicle cannot alter the set speed nor release the setting.
• The speed limitation device shall be fully capable of “withstanding the running.” Even if wrong operation, etc., of the speed limitation device should occur, it would not incur any increased output that will exceed the engine output determined by the condition of the accelerating devices, such as the depressing amount of the accelerator pedal.
• On motor vehicles equipped with “plural” accelerating devices, the speed limitation device shall actuate for every accelerating device.
• The speed limitation device shall not actuate the service brake device of the vehicle. However, the speed limitation device may actuate the auxiliary brake device only after the fuel supply has been minimized.
• The speed limitation device and connections necessary for its operation (except connections whose disconnection will prevent the normal motor vehicle operation) shall be capable of being protected from any unauthorized adjustments that will hamper the function of the speed limitation device or the interruption of its energy supply, such as power supply, by the attachment of sealing devices and/or the need to use special tools. However, this provision shall not apply to speed limitation devices whose function can be confirmed while the vehicle is stopping.
The conformity of these requirements is tested either by the use of a proving grounds test, a chassis dynamometer test, or by an engine bench test in the following ways:
The air inflation pressure of the tires shall be the value as posted in the specification table. Moreover, the tires shall be ones that have undergone break-in.
The weight of the test vehicle shall be the vehicle weight. However, on motor vehicles equipped with a spare tire and onboard tools, the test may be conducted with such articles mounted on the vehicle.
The surface of the proving ground shall be flat paved road. Gradients shall not exceed 2% and shall not vary by more than 1% excluding camber effects.
The surface of the proving ground shall be free from water pool, snow accumulation or ice formation.
The mean wind speed shall be less than 6 m/s. Moreover, the maximum wind speed shall not exceed 10 m/s.
The vehicle running at a speed 10 km/h below the set speed shall be accelerated as much as possible by operating the accelerator device,
○ The test shall be carried out for each gear ratio allowing in theory the set speed to be exceeded.
○ In this test, the speed of the test vehicle shall satisfy the following requirements enumerated below.
The stabilized speed shall not exceed the set speed plus 5 km/h nor a speed of 90 km/h.
After the stabilization speed has been reached for the first time, the maximum speed shall not exceed the stabilization speed multiplied by 1.05. Furthermore, the absolute value of the rate of change of speed shall not exceed 0.5 m/s
Within 10 seconds of first reaching the stabilized speed, the speed limitation function shall be controlled in such a way that the following requirements are satisfied.
The speed shall not vary by more than 4% of the stabilized speed or 2 km/h, whichever is greater.
The absolute value of the rate of change of speed shall not exceed 0.2 m/s
• The vehicle shall be driven at full acceleration up to the steady speed by operating the acceleration device,
• The test shall be carried out for each gear ratio allowing in theory the set speed to be exceeded.
○ In this test, the speeds of the test vehicle shall satisfy the following.
○ On each test run, the mean stabilized speed shall not exceed the set speed plus 5 km/h or a speed of 90 km/h.
○ The difference between the maximum value and the minimum value of the mean stabilized speeds obtained during each test run shall be no more than 3 km/h.
○ Conditions of chassis dynamometer
The equivalent inertia weight shall be set with an accuracy of ±10% of the vehicle weight of the test vehicle.
The vehicle running at a speed 10 km/h below the set speed shall be accelerated as much as possible by operating the accelerating device,
The load of the chassis dynamometer during the test shall be set to the forward running resistance of the test vehicle with an accuracy of 10%. Furthermore, when the competent authority approves it as appropriate, the load may be set to the maximum power of the engine multiplied by 0.4.
The test shall be carried out for each gear ratio allowing in theory the set speed to be exceeded.
○ The vehicle shall be driven at full acceleration up to the steady speed by operating the accelerating device,
○ The load of the chassis dynamometer shall be changed consecutively from the maximum power of the engine to the maximum power of the engine multiplied by 0.2.
○ The test shall be carried out for each gear ratio allowing in theory the set speed to be exceeded.
• In this test, the requirements prescribed shall be satisfied.
This test method can be carried out only when the competent authority recognizes that this bench test is equivalent to the proving ground measurement.
○ With regard to those motor vehicles equipped with a speed limitation device that has complied with the requirement of this Technical Standard, a mark shall be indicated at a place in the vehicle compartment where the driver can easily see the mark and at the rear end of the vehicle (excluding truck tractors).
NHTSA is proposing to establish a new FMVSS that would require new multipurpose passenger vehicles, trucks, buses, and school buses with a gross vehicle weight rating of more than 11,793.4 kilograms (26,000 pounds) to be equipped with a speed-limiting device. Additionally, as manufactured and sold, each vehicle would be required to have its device set to a specified speed. Although NHTSA has not specified a maximum set speed in this proposal, NHTSA intends to specify a maximum set speed in a final rule implementing this proposal. NHTSA has considered the benefits and costs of a 68 mph maximum set speed as requested in the petitions as well as 60 mph and 65 mph maximum set speeds in the overview of benefits and costs discussed in Section X of this document and in the Preliminary Regulatory Impact Analysis, Initial Regulatory Flexibility Analysis, and Draft Environmental Assessment accompanying this proposal.
To determine compliance with the operational requirements for the speed-limiting device (
Finally, to assist FMCSA's enforcement officials with post-installation inspections and investigations to ensure compliance with the speed limiting device maintenance requirement, NHTSA is proposing to require that the vehicle set
NHTSA solicits comment on all aspects of the proposed FMVSS, including the requirements for a speed-limiting device, the initial set speed requirement, the types of vehicles to which the speed limiting device requirements should be applicable, the proposed recording requirement and potential alternatives, and the proposed test procedure.
FMCSA is proposing an FMCSR requiring each CMV with a GVWR of more than 11,793.4 kilograms (26,000 pounds) to be equipped with a speed-limiting device meeting the requirements of the proposed FMVSS applicable to the vehicle at the time of manufacture, including the requirement that the device be set to a specified speed. As with the FMVSS, FMCSA has not specified the maximum set speed in this proposal, FMCSA intends to specify the maximum set speed in a final rule implementing this proposal. Motor carriers operating such vehicles in interstate commerce would be required to maintain the speed-limiting devices for the service life of the vehicle. FMCSA solicits comment on all aspects of this proposed FMCSR.
NHTSA is proposing that speed limiting device requirements apply to all new multipurpose passenger vehicles, trucks and buses with a gross vehicle weight rating of more than 11,793.4 kg (26,000 pounds). Although the majority of the estimated safety benefits of this joint rulemaking are for combination trucks because they travel more vehicle miles at high speeds, and thus are involved in more high-speed crashes, this rulemaking would also reduce the number of fatalities from crashes involving other types of heavy vehicles, some of which carry a large number of passengers. Additionally, because other heavy vehicles like single unit trucks and heavy buses have the same heavy-duty engines as combination trucks, the costs associated with installing the required speed-limiting devices in these vehicles would be minimal. For these reasons, the agency has tentatively concluded that it is appropriate to subject all types of heavy vehicles to the speed-limiting device requirements.
Regarding the GVWR threshold, NHTSA decided to focus the speed-limiting device requirements on those vehicles that carry the heaviest loads and for which small increases in speed have larger effects on the force of impact in a crash. These vehicles would also be subject to both FMCSA's regulations applicable to vehicles operated in interstate commerce and states' compatible regulations adopted as a condition of receiving Motor Carrier Safety Assistance Program (MCSAP) grants.
Specifically, NHTSA considered how FMCSA and its state partners could effectively enforce the proposed standard to realize the potential safety benefits. These benefits result from maintaining the speed-limiting devices after they are sold. In general, NHTSA does not have the authority to regulate the use of motor vehicles or motor vehicle equipment by vehicle owners. However, almost all of the vehicles with a GVWR over 11,793.4 kg (26,000 pounds) are CMVs and their maintenance is regulated by FMCSA through the FMCSRs.
NHTSA requests comment on the applicability of the proposed speed limiting device requirements, specifically whether the proposed requirements should apply to vehicles with a GVWR of 11,793.4 kg (26,000 pounds) or lower. We are interested in the costs, if any, to manufacturers of these lighter vehicles, as well as the costs to the operators of these vehicles—and, if applicable, the operators' customers—resulting from the additional travel time.
Consistent with the proposed FMVSS, the proposed FMCSR would also apply to each multipurpose passenger carrying vehicle, truck, bus and school bus (to the extent they fall under FMCSA jurisdiction) with a gross vehicle weight rating of more than 11,793.4 kilograms (26,000 pounds).
FMCSA requests comment on the cost of enforcement of the proposed FMCSR, training, new enforcement tools that may be required, and the costs, if any, to law enforcement partner agencies.
NHTSA's general approach in developing performance requirements for speed limiting devices was to identify key areas of performance pertinent to the overall effectiveness of speed limiting devices, thus reducing the severity of crashes, as well as to consider opportunities to harmonize the proposal with other global regulations. Considering that almost all vehicles covered by the proposed FMVSS are used for commercial purposes, the proposed requirements also include performance aspects to assist inspectors in the verification of the speed limiting device setting and pertinent speed determination parameter settings.
The proposed requirements are generally consistent with those in the UNECE regulation for vehicles with regard to limitation of their maximum speed. These requirements are located in part I of UNECE R89. While not all the provisions of the UNECE standard are pertinent to NHTSA's proposed regulation, we have evaluated this and other standards and have proposed specific text that best supports the purpose of the proposed FMVSS.
We are proposing three new definitions with respect to the speed limiting device. The first definition is the set speed (V
NHTSA is proposing that, as manufactured and sold, each vehicle's speed limiting device would be required to have a set speed of no greater than a speed to be specified in a final rule implementing this proposal. Although the petitions for rulemaking requested that NHTSA permit manufacturers to set the speed limiting device at any speed up to and including 68 mph, the agency has not proposed a specific set speed. In Section X of this document and in the Preliminary Regulatory Impact Analysis, Initial Regulatory Flexibility Analysis, and Draft Environmental Assessment accompanying this proposal, NHTSA has considered the benefits and costs of 60 mph, 65 mph, and 68 mph maximum set speeds.
The agencies estimate that limiting the speed of heavy vehicles to 60 mph would save 162 to 498 lives annually, limiting the speed of heavy vehicles to 65 mph would save 63 to 214 lives annually, and limiting the speed of heavy vehicles to 68 mph would save 27 to 96 lives annually. Although we believe that the 60 mph alternative would result in additional safety benefits, we are not able to quantify the 60 mph alternative with the same confidence as the 65 mph and 68 mph alternatives.
NHTSA also examined maximum posted speed limits for heavy vehicles. The following table shows the distribution of maximum posted speed limits.
The purpose of this joint rulemaking is to save lives by reducing the severity of crashes involving heavy vehicles. NHTSA and FMCSA are proposing to accomplish this by requiring that those vehicles be equipped with speed limiting devices. The proposed rules are not intended as a mechanism to enforce maximum speed limits set by States. However, the agencies are mindful that the proposed rules would limit the travel speed of heavy vehicles below the maximum posted speed limits in some States. We have therefore considered the distribution of State speed limits as one factor in deciding the appropriate set speed requirement. The above table illustrates that the vast majority of States (41 States) have maximum truck speed limits between 65 mph and 75 mph, with the most common maximum truck speed limits being 70 mph (21 States) and 65 mph (11 States).
We have also examined data from EMA
NHTSA will weigh all of these factors in choosing a maximum set speed for newly manufactured large vehicles and FMCSA will weigh these factors in considering what maximum set speed at which motor carriers would be required to maintain speed limiters. The benefits estimates indicate that substantially more lives would be saved if heavy vehicles are limited to 65 mph versus 68 mph with an additional increase in lives saved if heavy vehicles are limited to 60 mph instead of 65 mph. However, the agencies will also consider State speed limits and the economic impact on manufacturers and fleets including current speed limiter settings and the potential for harmonization with Ontario and Quebec maximum set speed requirements of 105 km/h (65 mph). NHTSA and FMCSA will consider other maximum set speeds both within that range of speeds and outside of it. NHTSA and FMCSA request comment on what an appropriate maximum set speed would be and why that speed should be chosen over other possible maximum set speeds.
We are proposing that the speed limiting device be permitted to allow normal acceleration control for the purpose of gear changing. It is important to provide acceleration control for the purpose of gear changing in order to maintain vehicle drivability. We note that, as proposed, the speed-limiting device must limit the speed of the vehicle regardless of the gear selection. Additionally, we are proposing that the maximum speed (overshoot) not exceed the stabilized speed by more than 5 percent. Likewise, the stabilized speed must not exceed the set speed.
Unlike UNECE R89, NHTSA is not proposing any requirement on manufacturers to make the speed limiting device tamper-resistant or to restrict modification of the speed limiting device settings. In other words, although the proposed FMVSS would require that the initial set speed be not greater than a specified speed, a speed limiting device could be capable of adjustment above the specified speed and still meet the requirements of the proposed FMVSS. However, because the proposed FMVSS would be reinforced by the proposed FMCSR, we expect that virtually all of these vehicles would be limited to the specified speed.
As described below, NHTSA is concerned about tampering and modification of the speed limiting device settings after a vehicle is sold. After considering various means of preventing these types of activities as described below in the Regulatory Alternatives section, the agency has tentatively decided not to include this type of requirement because of the costs that such a requirement would impose on manufacturers. NHTSA is also concerned about the feasibility of
In particular, the agency is concerned about speed limiting device setting adjustment and tampering that could allow vehicles to travel faster than the specified maximum set speed. The agency is also concerned about post-sale modification of the speed determination parameters such that they do not match the equipment on the vehicle or the failure to modify the parameters after replacing equipment. Either of these actions could result in the vehicle being capable of traveling at speeds higher than the set speed. Finally, the agency is concerned about potential tampering with the speed limiting device, such as hacking the ECU to disable the speed-limiting device, installing a device that sends a false signal to the speed-limiting device, or replacing the ECU with an ECU that does not limit the speed.
In contrast, NHTSA believes that some modifications should not be restricted, like adjusting the set speed below the maximum specified set speed and changing the speed determination parameter values as necessary to reflect replacement equipment (
In order to deter those types of activities that would allow a vehicle to travel above the maximum specified set speed, the proposed FMVSS would be reinforced by the proposed FMCSR, which would require motor carriers to maintain the speed limiting devices in accordance with the requirements of the proposed FMVSS. For example, the FMCSR would prohibit vehicle operators from adjusting the set speed above a maximum specified set speed.
To assist in verifying the performance of the speed limiting device while the vehicle is in use, NHTSA is proposing that the vehicle set speed and the speed determination parameters, such as tire size and gear ratios, be readable through the OBD connection. In addition to the current speed limiting device settings, NHTSA is proposing that the previous two setting modifications (
NHTSA seeks comment on the proposed speed limiting device setting readability requirements. For example, is reporting the time and date of setting modifications feasible or should some other value be specified (
NHTSA also seeks comment on any alternative approach that would allow inspectors to verify the speed limiting device settings at a reduced cost.
NHTSA is proposing a vehicle-level test that involves the acceleration of the vehicle on a test track. The agency is proposing various track and weather conditions, based on the widely utilized UNECE regulation and other vehicle tests that are conducted on test tracks, to ensure the repeatability of testing. The test begins with the vehicle traveling at a steady speed that is below the set speed. The vehicle is accelerated using a full positive action on the accelerator control. Such action is maintained for at least 30 seconds after the vehicle speed has been stabilized. During the testing, the instantaneous vehicle speed is recorded during the testing in order to establish the curve of speed versus time. A more detailed summary of the proposed test procedure follows.
The speed versus time curve would then be evaluated in order to find the stabilized speed and the maximum speed. Under the proposed requirements, the maximum speed achieved during the test must be no greater than 5 percent of the stabilized speed and the stabilized speed must not exceed the set speed. The agency notes that this proposed requirement is more stringent than the UNECE requirement, which specifies that the stabilized speed must be within 5 percent or 5 km/h of the set speed of the set speed. Adopting the UNECE tolerance would mean that a vehicle could have a stabilized speed of 5 km/h (3 mph) above the specified maximum set speed and still meet the proposed requirements. NHTSA will choose a maximum set sped based primarily on safety considerations with considerations also given to other benefits including fuel savings and the costs of the rule including opportunity costs due to slower deliveries. Whatever maximum speed is ultimately chosen, it will be based on these considerations and allowing vehicles to operate 5 km/h (3 mph) above the maximum set speed will lessen the benefits associated with the chosen maximum set speed. NHTSA
Additionally, NHTSA is not proposing to include the acceleration limits specified in the UNECE standard of 0.5 m/s
Given the extreme precision that would be required both of the speed control device and the test equipment, NHTSA proposes not to include the acceleration limits as specified in the UNECE standard. We seek comment as to the necessity of an acceleration limit and, if needed, what a reasonable limit could be.
FMCSA is proposing an FMCSR requiring each CMV with a GVWR of more than 11,793.4 kilograms (26,000 pounds) to be equipped with a speed limiting device meeting the requirements of the proposed FMVSS applicable to the vehicle at the time of manufacture, including the requirement that the device be set to a speed not greater than a specified maximum speed. This maximum speed will be based on the maximum speed chosen by NHTSA in a final rule implementing this proposal. Motor carriers operating such vehicles in interstate commerce would be required to maintain the speed limiting devices for the service life of the vehicle.
FMCSA's roadside enforcement activities are limited by the small size of its staff. The Agency therefore relies on its State partners for enforcement of its safety rules at the roadside. Through the Agency's Motor Carrier Safety Assistance Program (MCSAP), FMCSA provides Federal grants to the States to support the adoption and enforcement of compatible safety regulations. Therefore, FMCSA's adoption of a rule requiring interstate motor carriers to maintain speed limiting devices would be accompanied by the States' adoption of compatible rules applicable to both interstate and intrastate motor carriers pursuant to 49 CFR part 350.
The inclusion of the OBD feature for the speed limiting device would enable FMCSA and its State partners to enforce the proposed rule during roadside inspections, at the discretion of the Agency and its State partners. The enforcement of the requirements could be conducted in a targeted manner, periodically or randomly to provide an effective deterrent to carriers tampering with or disabling the device to avoid the need for the Agency and its State partners to consider changes to the standard inspection procedures or increases in the amount of time needed to complete a roadside inspection. FMCSA is again seeking comment and information regarding the cost of enforcement of the proposed FMCSR, training, new enforcement tools that may be required, and the costs, if any, to law enforcement partner agencies.
In addition, State law enforcement officials responsible for motor carrier safety oversight could cite CMV drivers for violations of the speed limiting device requirements as part of traffic enforcement activities. If the vehicle is observed to be operating in excess of a posted speed limit greater than the maximum specified set speed, and the vehicle was manufactured on or after the effective date of the proposed rule, the speeding violation would then serve as prima facie evidence that the speed limiting device was inoperative, or the setting altered. And, the driver could be subject both to a speeding ticket and motor carrier safety citation for operating a CMV with a speed limiting device that failed to meet the requirements of the State's version of the Federal requirement. Conversely, if the vehicle were clocked at the maximum specified set speed in a 50-mph zone, the driver could be ticketed for speeding, but the officer would make no assumption about the effectiveness of the speed limiting device.
In deciding on the approach proposed in this NPRM, NHTSA and FMCSA have examined the following alternatives to this proposal.
NHTSA also requests comment on the feasibility of technologies which would limit the speed of the vehicle to the speed limit of the road, as an alternative option to the a requirement limiting vehicle speed to a specified set speed. These technologies might include a GPS, vision system, vehicle to infrastructure communication, or some other autonomous vehicle technology. This could have the effect of reducing fatalities while limiting the economic effects of this rule on roads that have a posted speed above the maximum set speed. Heavy vehicle operators could also potentially choose between vehicles equipped with speed limiting devices set to a specified maximum set speed and vehicles with GPS-based, vision based, or vehicle-to-infrastructure-based, or other autonomous vehicle technology devices depending on their needs.
Our preliminary conclusion is that requiring these technologies to limit vehicle speed would not be feasible and/or cost-effective at this time, but the agencies are seeking comments from the public on this preliminary conclusion. The agencies would not publish a final rule requiring speed limiters using these technologies without first publishing another proposed rule addressing them. The agencies also request comment on whether they should consider allowing GPS-based speed limiters, which adjust to the actual speed limits on roads, to be used as an alternative means of compliance if conventional speed limiters are required.
The agencies understand that some trucking fleets use similar devices for monitoring purposes, but we have several questions about regulating a GPS-based, vision based, or vehicle-to-infrastructure-based device, and we invite comments on the following areas:
• What would be the costs associated with installing and maintaining a GPS-based, vision based, or vehicle-to-infrastructure-based speed limiting device?
• How easy would it be for a driver to interfere with the ability to receive speed limit information without detection and thereby travel faster than the posted speed limit? Are there tamper-resistant technologies available to limit such action?
• What is the best method for determining the posted speed limit on a given section of highway? For GPS-based systems, would the speed map need to be managed federally and made available to the vehicle during operation or could a third-party map be usable
• How would such a device handle posted speed changes such as dual day/night speed limits and construction zones?
• Is the current GPS coverage sufficient for such a device? How would temporary coverage outages be addressed for enforcement purposes?
• What would be the framework for a compliance test procedure?
• What are the limitations of the technologies in applications such as false positives?
• Should a speed-limiting device that is correlated to the highway speed still have a set speed lower than the posted speed limit?
As discussed above, at this time NHTSA is proposing to require a speed limiting device that reports the last two modifications of the set speed and the last two modifications of the speed determination parameters, along with the time and date of the modifications. NHTSA is not proposing any requirement on manufacturers to make the speed limiting device tamper resistant or to restrict modification of the speed limiting device settings. In other words, although the proposed FMVSS would require that the initial set speed be not greater than a maximum specified speed, a speed limiting device could be capable of adjustment above the maximum specified speed and still be compliant with the proposed FMVSS.
Although NHTSA is concerned about tampering and modification of the speed limiting device settings after a vehicle is sold, after considering various means of preventing these type of activities the agency has tentatively decided not to include a requirement to prevent tampering because of the costs that such requirements would impose on manufacturers and because we are concerned about the feasibility of establishing performance requirements that would be objective and effective in resisting various methods of tampering.
In general, there are several design approaches for restricting modification of the speed limiting device settings and/or making the ECU tamper resistant, namely through passwords (Pass Code) and coding of the device using hardware (Hard Code). The Pass Code design approach has two options. The first Pass Code option is to set the speed limiting device setting at the OEM factory. With the first Pass Code option, subsequent owners would be able to legitimately change the setting if vehicle components that would directly affect the speed limiting device performance are altered and recalibration is necessary. However, speed limiting devices with the first Pass Code option would not be tamper resistant. The second option is to set speed limiting device setting at the OEM factory and make it “factory password protected.” With the second Pass Code option, vehicle owners would have to make a formal request to either the vehicle or engine manufacturers to change the setting. According to EMA, if a vehicle owner needed to make any subsequent changes, it would cost approximately $300 per vehicle with the second Pass Code option. The Hard Code design approach is to hardcode the speed limiting device set speed in the ECU, based on characteristics of each vehicle produced. The Hard Code option would eliminate all possibilities of subsequent changes unless the entire ECU is replaced. With this approach, subsequent ECU changes would cost owners $2,000 or more.
In addition to the costs to manufacturers and vehicle owners that would result, such requirements would place an unrealistic burden on manufacturers to certify that equipment will resist methods of tampering that may be unknown at the time of certification. Although a basic password requirement may seem straightforward, establishing specific objective performance requirements for a password device that resists hacking would be challenging, and such requirements may not ultimately achieve the desired outcome of preventing tampering. Additionally, hacking methods that are unknown to the agency or to manufacturers could compromise such a tamper-resistant device. In the future, it may be possible to fool even a speed-limiting device that is hard coded into the ECU by providing false input signal.
NHTSA is also concerned that such devices could interfere with the types of modifications that NHTSA believes should not be restricted, like adjusting the set speed within the range of speeds up to the maximum specified set speed and changing the speed determination parameter values as necessary to reflect replacement equipment (
Given these concerns and the additional costs to vehicle manufacturers from installing devices that restrict modification of the speed limiting device settings and/or are tamper-resistant, NHTSA is not proposing to include these requirements. However, we invite comment on these various means of restricting modification of the speed limiting device, including their effectiveness and cost, as well as whether objective performance requirements can be established.
FMCSA proposes to enforce NHTSA's speed limiting device requirements for vehicles manufactured after the effective date of the FMVSS. Specifically, drivers and carriers would be subject to Federal civil penalties if they are determined to have operated CMVs with a GVWR of more than 26,000 pounds in interstate commerce when the speed limiting device is (1) not functioning, or (2) set at a maximum speed in excess of the maximum specified set speed. They would be subject to Federal civil penalties of up to $2,750 for drivers and up to $11,000 for employers who allow or require drivers to operate CMVs with speed limiting devices set at speeds greater than the maximum specified set speed.
If a speed limiting device is not functioning, drivers and carriers could avoid violations by driving no faster than the maximum specified set speed until the vehicle is repaired. Under 49 CFR part 396, drivers are required to prepare driver vehicle inspection reports (DVIRs) which document all defects or deficiencies observed by or reported to the driver during the work day. At any time the driver observes that the vehicle can exceed the maximum specified set speed, he or she should document the problem on the DVIR, which triggers a duty on the part of the motor carrier, upon receipt of the report, to correct the problem.
We are interested in receiving comments on ways to read the set speed and speed determination parameters other than through the OBD connection. Comments should consider ways to reduce the equipment cost required for enforcement officials based on roadside and facility-based enforcement programs.
NHTSA is proposing a test procedure that is similar to that in the UNECE R89 regulation, which is widely used in many parts of the world, as opposed to an independent test track procedure. We believe this approach limits the cost of certification to manufacturers and increases their ability to use common
The European standard includes the additional testing methods of vehicle dynamometer and engine dynamometer. These test methods may provide additional flexibility for manufacturers that are unable to use a test track, or during unfair weather conditions. We seek comment on whether NHTSA should consider these test methods as an option to our proposed track test.
Unlike the UNECE regulation, NHTSA has chosen not to include an electromagnetic disturbance requirement in the proposed FMVSS. The agency is concerned that speed limiting devices, as well as all safety critical electronic equipment, operate within the installed environment with respect to electromagnetic interference (EMI). However, if the agency finds a safety need to pursue EMI requirements, it will likely be conducted in a broad way that covers various electronic devices. At this time, the agency does not intend to apply EMI requirements on an ad hoc basis to specific regulations. The agency seeks comment on whether the EMI requirements of the UNECE regulation should be included in the FMVSS.
Road Safe America requested in its petition that all trucks manufactured after 1990 be required to be equipped with electronic speed governors. NHTSA is again seeking comment and information regarding the possibility of requiring all multipurpose passenger vehicles, trucks and buses manufactured after 1990 with a gross vehicle weight rating of more than 11,793.4 kg (26,000 pounds) to be retrofitted with electronic speed limiters.
The Secretary of Transportation has authority to promulgate safety standards for “commercial motor vehicles and equipment subsequent to initial manufacture.”
We seek to know more about the technical and economic feasibility of a retrofit requirement. In its comment to our 2007 Request for Comments, EMA expressed concern about retrofitting all post-1990 trucks. EMA's first concern related to retrofitting vehicles manufactured from 1990 to approximately 1994 to 1996, which were frequently equipped with mechanically controlled engines with mechanical speed limiting devices. EMA indicated that it would be impractical to retrofit these vehicles with modern ECUs and they estimated that it would cost $1,000 to $1,500 per vehicle to retrofit those vehicles currently without ECUs with a mechanical speed limiting device. EMA's second concern related to retrofitting ECU-equipped vehicles (
Hino Motors submitted a comment stating that it does not support the retrofitting of trucks that were manufactured with mechanically controlled engine devices, noting that it manufactured trucks with mechanically controlled engine devices through the model year 2003. The company stated that retrofitting older mechanically controlled engine devices with electronic controls would be costly to vehicle owners.
AAA requested that the agency explore the idea of retrofitting trucks currently on the road.
Based on the comments received, NHTSA is concerned that requiring the retrofitting of CMVs with speed limiting devices could be costly. Further, we understand that requiring retrofitted vehicles to meet every aspect of the performance requirements set forth in this proposal would impose additional costs beyond the costs associated with setting the speed limit. However, a number of these requirements are designed to assist enforcement personnel in the verification of the speed limiting device setting and pertinent vehicle parameter settings, and both NHTSA and FMCSA are concerned about the practicability of roadside enforcement if these were not included in any retrofit requirements. Given the agencies' concerns about technical feasibility, cost, enforcement, and impacts on small businesses, we are seeking public comment to improve our understanding of the real-world impact of implementing a speed limiting device retrofit requirement on existing vehicles and whether it is appropriate to have different requirements for these vehicles.
Please explain why the agency should (or should not) consider requiring a speed limiting device requirement for existing heavy vehicles. Please discuss:
a. What portions of the existing heavy vehicle fleet are not equipped with speed limiting devices, are equipped with mechanical speed limiting devices, or are equipped with ECUs? The agencies are also seeking this type of information for the fleets owned by small businesses.
b. How old are vehicles in each of these categories and what are their expected lifetimes? The agencies are also seeking this type of information for the fleets owned by small businesses.
c. In what model year did manufacturers cease manufacturing vehicles equipped with mechanically controlled engines?
d. Is it technically feasible to retrofit a vehicle equipped with a mechanically controlled engine with an ECU and if feasible what would be the cost to do so?
e. What technically feasible approaches, if any, are there to retrofit mechanical speed limiting devices so that they have some level of tamper resistance, and what are the costs of such approaches?
f. What technologies are available to increase the tamper resistance of speed limiting devices in ECUs and what would be the cost to retrofit existing vehicles with these technologies?
As an alternative to a retrofit requirement, the agencies request comment on whether to extend the set speed requirement to all CMVs with a GVWR of more than 26,000 pounds that are already equipped with a speed limiting device and how such a
If the proposed FMVSS is established, NHTSA is proposing a compliance date of the first September 1 three years after publication of a final rule. For illustration purposes, the proposed regulatory text uses the date of September 1, 2020. We believe that this lead time is appropriate as some design, testing, and development will be necessary to certify compliance to the new requirements. Three years is also consistent with the MCSAP time period for States to adopt regulations consistent with FMCSA standards.
Based on our review of the available data, if heavy vehicles were limited, it would reduce the severity of crashes involving these vehicles and reduce the resulting fatalities and injuries. The proposed rules would require that each vehicle, as manufactured and sold, have its speed limiting device set to a speed not greater than a maximum specified set speed, and that motor carriers maintain the set speed at a speed not greater than the maximum specified set speed. We expect that, as a result of this joint rulemaking, virtually all of these vehicles would be limited to that speed. In order to explore the benefits and costs of requiring speed limiters to be set at a variety of speeds, we have estimated the benefits and costs assuming that the affected vehicles are limited to speeds no greater than 60 mph, 65 mph, and 68 mph.
As explained above, most studies examining the relationship between travel speed and crash severity have concluded that the severity of a crash increases with increased travel speed.
Commenters who opposed the ATA and Road Safe petitions contend that the creation of speed differentials between cars and heavy vehicles would increase crash risk. There have been a number of studies conducted on the impact of speed differentials between cars and heavy vehicles and whether differential speeds increase vehicle interactions and crash risk. Two studies, one conducted by the Virginia Transportation Research Council (VTRC) and disseminated under sponsorship of the U.S. Department of Transportation, and the other conducted by the University of Idaho, observed no consistent safety effects of differential speed limits compared to uniform speed limits.
After considering this research and the difficulty in estimating the effect of speed limiting devices on crash risk, the agencies have chosen not to include an estimate of crashes avoided in the PRIA and to only estimate the benefits of reducing crash severity. Although this approach is conservative and the agencies believe that speed limiting devices will likely reduce both the severity and risk of crashes, the agencies have greater confidence that the estimated benefits described below will be fully realized because, by focusing on crash severity, the agencies are able to isolate more effectively the effects of speed reduction on safety. We invite public comment on these determinations and any additional information or studies related to the impact of speed limiting devices on crash avoidance that we should consider in estimating the effect of this rulemaking.
Using Fatality Analysis Reporting System (FARS) and National Automotive Sampling System General Estimates System (NASS GES) crash data over the 10-year period between 2004 and 2013, the agencies examined crashes involving heavy vehicles (
Among the 10,440 fatalities, 9,747 resulted from crashes involving combination trucks, 442 resulted from crashes involving single unit trucks and the remaining 251 resulted from crashes involving buses.
In order to estimate the safety benefits,
We have estimated the number of injuries that would be prevented using the ratio of fatalities to injuries resulting from certain crashes involving combination trucks.
Based on range of fatalities prevented, this rulemaking would prevent 179 to 551 serious injuries
Fatality and injury benefits are monetized in two parts. The first part is based on the value of a statistical life (VSL). Value-of-life measurements inherently include a value for lost quality of life plus a valuation of lost material consumption that is represented by measuring consumers' after-tax lost productivity. Additionally, there are costs to society incurred as a result of an injury or fatality that are separate from the value of the life saved/injury prevented. Benefits occur from reducing these economic costs of crashes by reducing the number of people injured or killed. These items include: reducing costs for medical care, emergency services, insurance administrative costs, workplace costs, and legal costs. These monetized benefits are reflected in Table 7 below. In addition to the safety benefits, this rule would result in reduced property damage as a result of making crashes less severe.
In addition to the safety benefits, the proposed rules would result in a reduction in fuel consumption due to increased fuel efficiency. To determine the fuel savings, the agencies used NASS GES and FARS data to estimate VMT on different types of roads (
The agencies predictions for fuel savings and total benefits, including greenhouse gas (GHG) emissions reduction.
For manufacturers, NHTSA expects the costs associated with the proposed FMVSS to be insignificant for new heavy vehicles because these vehicles already use ECUs for engine control. Regarding compliance test costs, truck manufacturers can use any appropriate method to certify to the performance requirements, including engineering analysis/calculation, computer simulation, and track testing. The agency believes that manufacturers will not need any tests additional to those they and their suppliers are currently conducting to verify the performance specifications.
This joint rulemaking would impose societal costs since the proposed speed setting will decrease the travel speed for trucks currently traveling faster than the maximum specified set speed (the same work will be done, but it will take longer to do it). This will result in increased travel time and potentially longer delivery times and a loss of a national resource. We have also accounted for a loss of value of goods as a result of increased travel time. In order to compensate for the increased travel time, trucking and bus companies would need to require current operators drive longer hours (within hours of service limits), hire additional operators, and use team driving strategies in some cases. We estimate the cost of this added time to be $1,534 million annually for 60 mph speed limiters, $514 million annually for 65 mph speed limiters, and $206 million annually for 68 mph speed limiters assuming a 7 percent discount rate. However, the estimated fuel savings offset these costs. In other words, even without considering the safety benefits, this joint rulemaking would be cost beneficial.
Although the proposed rules would apply to all heavy vehicles, the agencies' analysis indicates that this joint rulemaking could put owner-operators and small fleet owners, particularly those not using team driving strategies, at a disadvantage in some circumstances. Currently, there are transport jobs that small trucking companies could bid on and arrive one day sooner compared to a firm that already voluntarily uses a speed limiting device, if the small trucking company drives at 75 mph, which is the speed limit on some roads. Thus, it is likely that there are some jobs where there is an apparent competitive advantage to being able to drive faster. Some small businesses currently traveling at higher speeds might not be able to expand quickly enough to make the extra trips necessary to compensate for the increased travel times resulting from limiting their speed. Instead of these small independent trucking companies buying new trucks and/or hiring additional drivers, we expect that large trucking companies would absorb the additional cargo with their reserve capacity of trucks and drivers.
Although the agencies do not expect additional costs to the trucking industry as a whole in the near future from this rulemaking, small trucking companies, especially independent owner-operators, would be less profitable with speed limiting devices set. We have very limited data to predict how the affected owner-operators would deal with the increase in delivery times. We expect that some of the affected owner-operators would work for trucking companies as independent contractors. If all of the affected owner-operators worked for trucking companies as independent contractors, they would lose $54 million in labor income. Our data is even more limited for entities that operate buses, but we expect that some small motorcoach companies may have to hire additional drivers to compensate for the increased travel times resulting from speed limiting devices.
We request comment on the agencies' assumptions regarding how this rulemaking would affect small heavy vehicle operators, and we request comment on the type and magnitude of that effect.
Although this rulemaking is expected to result in large fuel savings to the trucking industry as a whole, the agencies have limited data on the travel speeds of and vehicle miles traveled (VMT) by trucks operated by small companies as compared to trucks operated by large companies. Accordingly, it is difficult to estimate the relative fuel savings for small companies. However, we have anecdotal evidence suggesting that the VMT by trucks operated by small companies is 30 percent of the total VMT by all commercial vehicles. Assuming that there is no difference in travel speed between trucks operated by small companies and trucks operated by large companies, 30 percent of the fuel savings resulting from the proposed rule would be realized by small trucking companies. In order to improve our estimate, which, as mentioned above, is based on limited data and certain assumptions, the agencies request comments on VMT and vehicle travel speed for different sizes of truck carriers and bus companies.
These proposed rules are cost beneficial. Combining the value of the ELS, the property savings, and the fuel savings, the total benefits are greater than the estimated cost, even assuming that the proposed rule would result in the low benefits estimate.
For further explanation of the estimated benefits and costs, see the PRIA provided in the docket for this proposal.
Your comments must be written and in English. To ensure that your comments are correctly filed in the Docket, please include the docket number of this document in your comments.
Your comments must not be more than 15 pages long (49 CFR 553.21). We established this limit to encourage you to write your primary comments in a concise fashion. However, you may attach necessary additional documents to your comments. There is no limit on the length of the attachments.
Comments may be submitted to the docket electronically by logging onto the Docket Management System Web site at
You may also submit two copies of your comments, including the attachments, to Docket Management at the address given above under
Please note that pursuant to the Data Quality Act, in order for substantive data to be relied upon and used by the agency, it must meet the information quality standards set forth in the OMB and DOT Data Quality Act guidelines. Accordingly, we encourage you to consult the guidelines in preparing your comments. OMB's guidelines may be accessed at
If you wish Docket Management to notify you upon its receipt of your comments, enclose a self-addressed, stamped postcard in the envelope containing your comments. Upon receiving your comments, Docket Management will return the postcard by mail.
If you wish to submit any information under a claim of confidentiality, you should submit three copies of your complete submission, including the information you claim to be confidential business information, to the Chief Counsel, NHTSA, at the address given above under
We will consider all comments that Docket Management receives before the close of business on the comment closing date indicated above under
You may read the comments received by Docket Management at the address given above under
Please note that even after the comment closing date, we will continue to file relevant information in the Docket as it becomes available. Further, some people may submit late comments. Accordingly, we recommend that you periodically check the Docket for new material.
Executive Order 12866, Executive Order 13563, and the Department of Transportation's regulatory policies require the agencies to make determinations as to whether a regulatory action is “significant” and therefore subject to OMB review and the requirements of the aforementioned Executive Orders. Executive Order 12866 defines a “significant regulatory action” as one 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 the Executive Order.
We have considered the potential impact of this proposal under Executive Order 12866, Executive Order 13563, and the Department of Transportation's regulatory policies and procedures. This joint rulemaking is economically significant because it is likely to have an annual effect on the economy of $100 million or more. Thus it was reviewed by the Office of Management and Budget under E.O. 12866 and E.O. 13563. The rulemaking action has also been determined to be significant under the Department's regulatory policies and procedures. The Preliminary Regulatory Impact Analysis (PRIA) fully discusses the estimated costs and benefits of this joint rulemaking action. The costs and benefits are also summarized in Section X of this preamble.
Pursuant to the Regulatory Flexibility Act, Public Law 96-354, 94 Stat. 1164 (5 U.S.C. 601
The agencies believe that the proposed rules will affect small businesses, and may have a significant economic impact on a substantial number of small businesses. Accordingly, we have included an initial regulatory flexibility analysis in the PRIA detailing these effects and summarized these effects in Section X.B. of this preamble. We summarize the initial regulatory flexibility analysis below.
Agencies are required to prepare and make available for public comment an initial regulatory flexibility analysis (IRFA) describing the impact of proposed rules on small entities if the agency determines that the rule may have a significant economic impact on a substantial number of small entities. Each IRFA must contain:
(1) A description of the reasons why action by the agency is being considered;
(2) A succinct statement of the objectives of, and legal basis for, the proposed rule;
(3) A description of and, where feasible, an estimate of the number of small entities to which the proposed rule will apply;
(4) A description of the projected reporting, record keeping and other compliance requirements of a proposed rule including an estimate of the classes of small entities which will be subject to the requirement and the type of
(5) An identification, to the extent practicable, of all relevant Federal rules which may duplicate, overlap, or conflict with the proposed rule;
(6) Each initial regulatory flexibility analysis shall also contain a description of any significant alternatives to the proposed rule which accomplish the stated objectives of applicable statutes and which minimize any significant economic impact of the proposed rule on small entities.
As described in greater deal above, studies examining the relationship between travel speed and crash severity have confirmed the common-sense conclusion that the severity of a crash increases with increased travel speed.
After conducting an analysis of crash data and data on heavy vehicle travel speeds, the agencies have determined that reducing heavy vehicle travel speed would reduce the severity of crashes involving these vehicles and reduce the number of resulting fatalities. After analyzing several set speeds, including 60 mph, 65 mph, and 68 mph, NHTSA is proposing to heavy vehicles to be equipped with a speed limiting system. As manufactured and sold, each of these vehicles would be required by NHTSA to have a speed limiting device to set a particular speed.
FMCSA is proposing a complementary Federal motor carrier safety regulation (FMCSR) requiring multipurpose passenger vehicles, trucks, and buses and school buses with a GVWR of more than 11,793.4 kilograms (26,000 pounds) to be equipped with a speed limiting system meeting the requirements of the proposed FMVSS applicable to the vehicle at the time of manufacture. Motor carriers operating such vehicles in interstate commerce would be required to maintain the speed limiting systems for the service life of the vehicle.
The objectives of the proposed rule are to reduce the severity of crashes involving heavy vehicles and reduce the number of fatalities. Since this NPRM would apply both to vehicle manufacturers and motor carriers that purchase and operate these vehicles, this joint rulemaking is based on the authority of both NHTSA and FMCSA. The legal authorities for NHTSA and FMCSA are described in Section II, above.
The proposed FMVSS would apply to manufacturers of multipurpose passenger vehicles, trucks, and buses, with a GVWR of more than 11,793.4 kilograms (26,000 pounds). The proposed FMCSR would apply to motor carriers operating such vehicles in interstate commerce.
We believe there are very few manufacturers of heavy trucks in the United States which can be considered small businesses. The heavy truck industry is highly concentrated with large manufacturers, including Daimler Trucks North America (Freightliner, Western Star), Navistar International, Mack Trucks Inc., PACCAR (Peterbilt and Kenworth) and Volvo Trucks North America, accounting for more than 99% of the annual production. We believe that the remaining trucks (less than 1 percent) are finished by final stage manufacturers. With production volume of less than 1 percent annually, these remaining heavy truck manufacturers are most likely small businesses.
NHTSA believes there are approximately 37 bus manufacturers in the United States. Of these, 10 manufacturers are believed to be small businesses: Advanced Bus Industries, Ebus Inc., Enova Systems, Gillig Corporation, Krystal Koach Inc., Liberty Bus, Sunliner Coach Group LLC, TMC Group Inc., Transportation Collaborative, Inc., Van-Con, Inc.
The motor carriers regulated by FMCSA operate in many different industries. Most for-hire property carriers fall under North American Industrial Classification System (NAICS) subsector 484, Truck Transportation, and most for-hire passenger transportation carriers fall under NAICS subsector 485, Transit and Ground Passenger Transportation. The SBA size standard for NAICS subsector 484 is currently $25.5 million in revenue per year, and the SBA size standard for NAICS subsector 485 is currently $14 million in revenue per year.
Because the agencies do not have direct revenue figures for all carriers, power units (PUs) serve as a proxy to determine the carrier size that would qualify as a small business given the SBA's revenue threshold. In order to produce this estimate, it is necessary to determine the average revenue generated by a PU unit.
With regard to truck PUs, FMCSA determined in the Electronic On-Board Recorders and Hours-of-Service Supporting Documents Rulemaking RIA
With regard to passenger-carrying vehicles, FMCSA conducted a
Regarding bus companies, we believe that the companies most likely to be affected would be those that operate motorcoaches, which tend to be larger buses that are used for traveling longer distances. FMCSA data indicates that there are approximately 4,168 authorized motorcoach carriers, 813 of which own or lease only one motorcoach. The median number of motorcoaches owned or leased by these companies is 3. Accordingly, we estimate that most of the 4,168 motorcoach companies are small entities with annual revenues of less than $14 million per year.
The agencies request comments on the percentage of small carrier business that might be affected by the proposed speed limiting device requirements.
The impact on manufacturers of heavy vehicles, whether they are large or small businesses, would be minimal, because these vehicles are already equipped with electronic engine controls that include the capability to limit the speed of the vehicle.
FMCSA is proposing a complementary Federal motor carrier safety regulation (FMCSR) requiring multipurpose passenger vehicles, trucks, and buses with a GVWR of more than 11,793.4 kilograms (26,000 pounds) to be equipped with a speed limiting system meeting the requirements of the proposed FMVSS applicable to the vehicle at the time of manufacture. Motor carriers operating such vehicles in interstate commerce would be required to maintain the speed limiting systems for the service life of the vehicle.
The impact on small carriers could be significant from a competitive perspective. Regarding small trucking companies, the agencies predict that a speed limiting device might take away certain competitive advantages that small carriers might have over large trucking firms that already utilize speed limiting devices, but we have very limited knowledge of knowing whether that impact is 10 percent of their business, or more or less. We estimated that independent owner-operators of combination trucks and single unit trucks would drive 33,675 million miles annually out of 112,249 million miles traveled by these vehicles on rural and urban interstate highways. With the estimated average wage of $0.32/mile, the total annual revenue would be $10,776 million. As described in detail earlier in the PRIA, unlike large trucking companies, small carriers with limited resources may not be able to increase the number of drivers to overcome the delay in delivery time. However, the competitive impacts are difficult to estimate. For example, with 65 mph speed limiting devices, we estimated that owner-operators would lose $50 million annually. Accordingly, owner-operators would lose not more than 1% of their labor revenue. However, we note that the estimates were made based on very limited data. The agencies request comment on how large the economic impact might be on owner-operators.
Regarding small motorcoach companies, we have even more limited data to predict how affected small motorcoach companies would compensate for the delay in delivery time or to quantify the effect on those businesses. Like small trucking companies, small motorcoach companies might need additional drivers to cover the same routes with a speed limiting device if the speed limiting device reduces the distance they can travel within their maximum hours of service. If those companies were unable to hire additional drivers, they would likely lose market share to larger companies that could afford additional drivers.
The agencies believe that the proposed rule will affect small businesses, as discussed above; and may have a significant economic impact on a substantial number of small businesses. We request comment on the agencies' assumptions regarding how this rulemaking would affect small heavy vehicle operators, and we request comment on the type and magnitude of that effect.
Although the heavy vehicle fuel efficiency program allows speed limiting devices as a compliance option for vehicle manufacturers, it does not require the devices.
Although the proposed speed limiting device requirements are different than those for speed limiting devices under the fuel efficiency program, the requirements are not incompatible, and manufacturers would be able to design speed limiting devices that satisfy the requirements of the proposed FMVSS and the requirements necessary for the devices to be used for compliance with the fuel efficiency program. Manufacturers that choose to use speed limiting systems as a means of compliance with the fuel efficiency program would need to design a system that meets the requirements of both the program and the proposed FMVSS,
The agencies examined the expected benefits and costs of alternative speed limiting requirements, including different maximum speed settings, various tamper resistance requirements, and alternative compliance test procedures. The agencies are also requesting comment on the potential alternative of tying set speed to the speed limit of the road using GPS, vision, or vehicle-to-infrastructure based technologies.
When speed limiters are required to set speeds at a particular speed, the requirement potentially imposes costs on CMV operators, including the small operators. A higher proposed speed setting would reduce the costs resulting from additional travel time. As explained in detail in the Unfunded Mandates Reform Act analysis, NHTSA and FMCSA carefully explored the initial speed setting. The benefits estimate showed that limiting vehicles to a speed of 65 mph would save substantially more lives than the slightly higher speed setting of 68 mph. This speed setting would also harmonize U.S. requirements with those of Ontario and Quebec.
The agencies requests comment on how the rule will impact small businesses and alternatives that would accomplish the objectives of the rulemaking while minimizing the impacts to small businesses.
NHTSA and FMCSA have examined today's NPRM pursuant to Executive Order 13132 (64 FR 43255, August 10, 1999) and concluded that no additional consultation with States, local governments or their representatives is mandated beyond the rulemaking process. The agencies have concluded that the rulemaking would not have sufficient federalism implications to warrant consultation with State and local officials or the preparation of a federalism summary impact statement. The proposed rule would 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.”
NHTSA rules can have preemptive effect in two ways. First, the National Traffic and Motor Vehicle Safety Act contains an express preemption provision:
When a motor vehicle safety standard is in effect under this chapter, a State or a political subdivision of a State may prescribe or continue in effect a standard applicable to the same aspect of performance of a motor vehicle or motor vehicle equipment only if the standard is identical to the standard prescribed under this chapter.
The proposed FMVSS would preempt State laws or regulations addressing heavy vehicle speed limiting devices. However, the proposed FMVSS would not affect the States' ability to set maximum speed limits for public roads and highways, even if the posted speed limits for heavy vehicles are different than the set speed mandated when the vehicles are manufactured and sold.
The express preemption provision described above is subject to a savings clause under which “[c]ompliance with a motor vehicle safety standard prescribed under this chapter does not exempt a person from liability at common law.” 49 U.S.C. § 30103(e) Pursuant to this provision, State common law tort causes of action against motor vehicle manufacturers that might otherwise be preempted by the express preemption provision are generally preserved. However, the Supreme Court has recognized the possibility, in some instances, of implied preemption of State common law tort causes of action by virtue of NHTSA's rules—even if not expressly preempted.
This second way that NHTSA rules can preempt is dependent upon the existence of an actual conflict between an FMVSS and the higher standard that would effectively be imposed on motor vehicle manufacturers if someone obtained a State common law tort judgment against the manufacturer—notwithstanding the manufacturer's compliance with the NHTSA standard. Because most NHTSA standards established by an FMVSS are minimum standards, a State common law tort cause of action that seeks to impose a higher standard on motor vehicle manufacturers will generally not be preempted. However, if and when such a conflict does exist —for example, when the standard at issue is both a minimum and a maximum standard—the State common law tort cause of action is impliedly preempted. See
Pursuant to Executive Order 13132, NHTSA has considered whether this rule could or should preempt State common law causes of action. The agency's ability to announce its conclusion regarding the preemptive effect of one of its rules reduces the likelihood that preemption will be an issue in any subsequent tort litigation.
To this end, NHTSA has examined the nature (
With a few exceptions not applicable here, FMCSA regulations do not have preemptive effect. However, States that accept MCSAP grant funds—currently all 50 States and the District of Columbia—must adopt regulations “compatible” with many provisions of the FMCSRs. Pursuant to MCSAP, participating States would be required to adopt and enforce, within 3 years of the effective date of a final rule, State laws or regulations applicable both to interstate and intrastate commerce that have the same effect as proposed 49 CFR 393.85. In other words, States would have to prohibit even motor carriers operating entirely in intrastate commerce from re-setting their speed limiting devices to speeds above the maximum specified set speed. Because State participation in MCSAP is voluntary, the program does not have federalism implications.
We solicit the comments of the States and other interested parties on this assessment of issues relevant to E.O. 13132.
When promulgating a regulation, Executive Order 12988 specifically
Pursuant to this Order, NHTSA and FMCSA note as follows. The preemptive effect of this proposal is discussed above in connection with Executive Order 13132. NHTSA and FMCSA note further that there is no requirement that individuals submit a petition for reconsideration or pursue other administrative proceeding before they may file suit in court.
The policy statement in section 1 of Executive Order 13609 provides, in part:
The regulatory approaches taken by foreign governments may differ from those taken by U.S. regulatory agencies to address similar issues. In some cases, the differences between the regulatory approaches of U.S. agencies and those of their foreign counterparts might not be necessary and might impair the ability of American businesses to export and compete internationally. In meeting shared challenges involving health, safety, labor, security, environmental, and other issues, international regulatory cooperation can identify approaches that are at least as protective as those that are or would be adopted in the absence of such cooperation. International regulatory cooperation can also reduce, eliminate, or prevent unnecessary differences in regulatory requirements.
The regulatory approaches to speed limiting devices taken by certain foreign governments are discussed in Section V above. The proposed FMVSS adopts an approach that is similar to the widely used UNECE regulation. Specifically, NHTSA is proposing a test procedure substantially patterned after UNECE R89, which is described above. NHTSA requests public comment on whether (a) the “regulatory approaches taken by foreign governments” concerning the subject matter of this rulemaking and (b) the above policy statement have any implications for this rulemaking.
This rulemaking would not effect a taking of private property or otherwise have takings implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.
The regulations implementing Executive Order 12372 regarding intergovernmental consultation on Federal programs and activities do not apply to this action.
We analyzed this rulemaking under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, and determined that it does not have a substantial effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes.
We analyzed this action under Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks. We determined that this NPRM would not pose an environmental risk to health or safety that might affect children disproportionately.
FMCSA analyzed this action under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use. We have determined that it is not a “significant energy action” under that Executive Order because while this is an economically significant rulemaking it is not likely to have an adverse effect on the supply, distribution, or use of energy. In fact, this rulemaking would have a positive impact on the energy supply.
Under the National Technology Transfer and Advancement Act of 1995 (NTTAA) (Pub. L. 104-113) (15 U.S.C. 3701 note), “all Federal agencies and departments shall use technical standards that are developed or adopted by voluntary consensus standards bodies, using such technical standards as a means to carry out policy objectives or activities determined by the agencies and departments.” Voluntary consensus standards are technical standards (
NHTSA and FMCSA are not aware of any voluntary consensus standards related to the proposed speed limiting device requirements that are available at this time. However, we will consider any such standards as they become available and seek comment on whether any such standards exist.
The Unfunded Mandates Reform Act of 1995 requires agencies to prepare a written assessment of the costs, benefits and other effects of proposed or final rules that include a Federal mandate likely to result in the expenditure by State, local or tribal governments, in the aggregate, or by the private sector, of more than $100 million annually (adjusted for inflation with base year of 1995). In 2013 dollars, this threshold is $141 million. This joint rulemaking is not expected to result in the expenditure by State, local, or tribal governments, in the aggregate, of more than $141 million annually, but the proposed rules could result in the expenditure of that magnitude by the private sector.
As noted previously, the agencies have prepared a detailed economic assessment in the PRIA. That assessment analyzes the benefits and costs of the proposed speed limiting device requirements for multipurpose passenger vehicles, trucks, buses, and school buses with a gross vehicle weight rating of more than 11,793.4 kilograms (26,000 pounds). The agencies' preliminary analysis indicates that although the proposed rule would result in minimal costs to vehicle manufacturers, it could result in expenditures by CMV operators of $1,534 million annually for 60 mph speed limiters, $514 million annually for 65 mph speed limiters, and $206 million annually for 68 mph speed limiters assuming a 7 percent discount rate. This is because limiting vehicles to speeds will increased travel time.
The PRIA also analyzes the expected benefits and costs of alternative speed
Additionally, as described in Section X.A.2, above, the agencies estimate that the proposal would result in substantial fuel savings. The fuel savings would offset the costs to CMV operators resulting from increased travel time. Assuming that vehicle manufacturers design their speed limiting devices so that the devices also meet the necessary requirements to be used for compliance with the medium- and heavy-duty vehicle fuel efficiency program (which the agencies expect they will),
Specifically, under the medium- and heavy-duty vehicle fuel efficiency program, heavy vehicle drive cycles are evaluated at a maximum speed of 65 mph,
Comparing the costs and fuel savings of the various speed setting alternatives, which are discussed in detail in the PRIA, the agencies estimate that limiting heavy vehicles to 68 mph would result in $209 million in costs (assuming a 7 percent discount rate) from increased travel times, as compared to $523 million in costs associated with limiting vehicles to 65 mph. However, the cost difference would be offset by additional fuel savings that would be realized with a 65 mph speed setting versus a 68 mph speed.
The agencies estimate that limiting heavy vehicles to 60 mph would result in $1,561 million in costs (assuming a 7 percent discount rate) from increased travel times,
NHTSA and FMCSA have analyzed this NPRM for the purpose of the National Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321
NHTSA and FMCSA have reviewed the information presented in the Draft EA and conclude that the proposed action would have an overall positive impact on the quality of the human environment. In particular, the agencies anticipate reductions in most harmful air pollutant emissions, benefits from reduced fuel use (including reductions in carbon dioxide emissions), and reductions in releases of solid waste and hazardous materials corresponding to reductions in crash severity. The Draft EA shows anticipated increases in some harmful air pollutant emissions. The degree of impacts for each alternative correlate with the degree of speed reduction anticipated under that alternative. Overall, these impacts are not anticipated to be great in intensity, and they will occur so far into the future (as a result of slow fleet turnover where new vehicles subject to the requirements make up only a small percentage of on-road vehicles in the short term) that they are subject to considerable uncertainty. Still, for each action alternative, the environmental impacts of the proposed action are expected to be beneficial when taken together and are not expected to rise to a level of significance that necessitates the preparation of an Environmental Impact Statement.
The Draft EA is open for public comment. The agencies will consider all comments received in preparing and reviewing the Final EA. At this time, based on the information in the Draft EA and assuming no additional information or changed circumstances, the agencies expect to issue a Finding of No Significant Impact. A FONSI, if appropriate, would be issued concurrent with the Final EA. However, any such finding will not be made before careful review of all comments.
We evaluated the environmental effects of this NPRM in accordance with E.O. 12898 and determined that there are neither environmental justice issues
Under the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3501,
Executive Order 12866 requires each agency to write all rules in plain language. Application of the principles of plain language includes consideration of the following questions:
• Have we organized the material to suit the public's needs?
• Are the requirements in the rule clearly stated?
• Does the rule contain technical language or jargon that isn't clear?
• Would a different format (grouping and order of sections, use of headings, paragraphing) make the rule easier to understand?
• Would more (but shorter) sections be better?
• Could we improve clarity by adding tables, lists, or diagrams?
• What else could we do to make the rule easier to understand?
If you have any responses to these questions, please include them in your comments on this proposal.
Section 522 of Title I of Division H of the Consolidated Appropriations Act, 2005, enacted December 8, 2004 (Pub. L. 108-447, 118 Stat. 2809, 3268, 5 U.S.C. 552a note), requires the agencies to conduct a privacy impact assessment (PIA) of a proposed regulation that will affect the privacy of individuals. This joint rulemaking would not require the collection of any personally identifiable information or otherwise affect the privacy of individuals, and thus no PIA is required.
The Department of Transportation assigns a regulation identifier number (RIN) to each regulatory action listed in the Unified Agenda of Federal Regulations. The Regulatory Information Service Center publishes the Unified Agenda in April and October of each year. You may use the NHTSA and FMCSA RINs contained in the heading at the beginning of this document to find this action in the Unified Agenda.
Highways and roads, Incorporation by reference, Motor carriers, Motor vehicle equipment, Motor vehicle safety.
Imports, Incorporation by reference, Motor vehicle safety, Reporting and recordkeeping requirements, Tires.
In consideration of the foregoing, FMCSA and NHTSA propose to amend 49 CFR parts 393 and 571, respectively, as follows:
49 U.S.C. 31136, 31151, and 31502; sec. 1041(b) of Pub. L. 102-240, 105 Stat. 1914, 1993 (1991); sec. 5524 of Pub. L. 114-94, 129 Stat. 1312, 1560; and 49 CFR 1.87.
Each multipurpose passenger vehicle, truck, bus and school bus with a gross vehicle weight rating of more than 11,793.4 kilograms (26,000 pounds) manufactured on or after September 1, 2020, shall be equipped with a device that limits its speed to [a speed to be specified in a final rule] as required by Federal Motor Vehicle Safety Standard No. 140 (49 CFR 571.140).
49 U.S.C. 322, 30111, 30115, 30117, and 30166; delegation of authority at 49 CFR 1.95.
S1.
S2.
S3.
S4.
S5.
S5.1
S5.1.1
S5.1.1.1
S5.1.1.2
(a) If the V
(b) If the V
S5.1.1.3
(a) If the speed determination parameter has changed once, the previous value for each changed parameter and the time and date of the parameter change.
(b) If the speed determination parameter has changed two or more times, the two most recent values for the parameter set prior to the current parameter value and the time and date of the two most recent changes to the parameter.
S5.1.2
S5.2
S5.2.1 The set speed (V
S5.2.2 After the vehicle speed has reached 95% of V
S5.2.3 Ten seconds after the vehicle first reaches 95% of V
S5.2.3.1 The vehicle speed shall not vary by more than ±2% of V
S5.2.3.2 V
S5.3 The speed limiting device may allow normal acceleration control for the purpose of gear changing.
S6.
S6.1
S6.1.1 The ambient temperature is between 7° C (45 °F) and 40° C (105 °F).
S6.1.2 The wind speed is less than 5m/s (11 mph).
S6.2
S6.2.1 The test track is suitable to enable a stabilization speed to be maintained and the test surface is solid-paved, uniform, without irregularities, undulations, dips or large cracks. Gradients do not exceed 2% and do not vary by more than 1% excluding camber effects.
S6.2.2 The test surface is free from standing water, snow, or ice.
S6.3
S6.3.1 Tires. The vehicle is tested with the tires installed on the vehicle at the time of initial vehicle sale. The tires are inflated to the vehicle manufacturer's recommended cold tire inflation pressure(s).
S6.3.2 The vehicle is tested in an unloaded condition with a single operator and necessary test equipment.
S6.3.3 A truck tractor is tested without a trailer.
S6.4
S6.4.1 The speed measurement is independent of the vehicle speedometer and is accurate within plus or minus 1%.
S7.
S7.1 The vehicle, running at a speed which is 10 km/h below the set speed, is accelerated at a smooth and progressive rate using a full positive action on the accelerator control.
S7.2 This action is maintained at least 30 seconds after the vehicle speed has reached 95% of V
S7.3 The instantaneous vehicle speed is recorded at a frequency of at least 100 Hz during the testing in order to establish the speed versus time plot as shown in Figure 1.
S7.4 V
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 |