section_id,title_number,title_name,chapter,subchapter,part_number,part_name,subpart,subpart_name,section_number,section_heading,agency,authority,source_citation,amendment_citations,full_text 40:40:27.0.1.1.5.1.9.1,40,Protection of Environment,I,F,195,PART 195—RADON PROFICIENCY PROGRAMS,A,Subpart A—General Provisions,,§ 195.1 Purpose and applicability.,EPA,,,,"(a) Purpose. The purpose of this part is to establish and collect the fees from applicants and participants required by section 305 of the Toxic Substances Control Act, U.S.C. 2665 to defray the cost to EPA for operating the following programs: The National Radon Measurement Proficiency (RMP) Program, the individual proficiency component of the RMP Program, and the National Radon Contractor Proficiency (RCP) Program. (b) Applicability. This part applies to all applicants and participants in the following EPA programs: The National Radon Measurement Proficiency Program, the individual proficiency component of the RMP Program, and the National Radon Contractor Proficiency Program." 40:40:27.0.1.1.5.1.9.2,40,Protection of Environment,I,F,195,PART 195—RADON PROFICIENCY PROGRAMS,A,Subpart A—General Provisions,,§ 195.2 Definitions.,EPA,,,,"Definitions in 15 U.S.C. 2602 and 2662 apply to this part unless otherwise specified in this section. In addition, the following definitions apply: Acceptance date means the date on which EPA enters the application into the data system. Accepted application refers to an application that has been entered into the data system. Applicant means an individual or organization that submits an application to the RMP program, including the individual proficiency component of the RMP program, or the RCP program. An applicant to the RMP program must submit a separate application for each location from which it provides radon measurement services. After the application is accepted by EPA, the applicant becomes a “participant” in the proficiency programs. Application means the documents submitted to EPA by applicants to the RMP and RCP programs which request participation in a program. Device/measurement device means a unit, component, or system designed to measure radon gas or radon decay products. EPA means the U.S. Environmental Protection Agency. Individual proficiency/RMP exam means the exam which evaluates individuals who provide radon measurement services in a residential environment. Listed participant in an individual or organization who has met all the requirements for listing in the RMP and RCP programs. Measurement method is a means of measuring radon gas or radon decay products encompassing similar measurement devices, sampling techniques, or analysis procedures. Organization is any individual, sole proprietorship, partnership, business, company, corporation, college or university, government agency (includes Federal, State and local government entities), laboratory, or institution. Participant is an individual or organization engaged in radon measurement and/or mitigation activities or in offering radon measurement and/or mitigation services to consumers and others, whose proficiency program application EPA has accepted. Primary measurement services (primary) refers to radon measurement services using a specific device which services include the capability to read and/or analyze the results generated from the device. Radon Contractor Proficiency (RCP) program refers to EPA's program to evaluate radon mitigation contractors and the contractor's ability to communicate information to the public. Radon Measurement Proficiency (RMP) program refers to EPA's program to evaluate organizations and individuals offering measurement services to consumers. It provides a means for organizations to demonstrate their proficiency in measuring radon and its decay products in indoor air. Radon mitigation contractor means a contractor who provides radon mitigation services to the public. Secondary radon measurement services (secondary) refers to radon measurement services that do not include the reading or the ability to analyze the results of the measurement devices used. These services may include placement and retrieval of devices, reporting results, and/or consultation with consumers." 40:40:27.0.1.1.5.2.9.1,40,Protection of Environment,I,F,195,PART 195—RADON PROFICIENCY PROGRAMS,B,Subpart B—Fees,,§ 195.20 Fee payments.,EPA,,,"[60 FR 41816, Aug. 14, 1995]","(a) Fee Amounts. Applicants to and participants in the RMP and RCP programs shall pay fees according to the following fee schedule: (1) Organizations Listed for or Seeking Listing for Primary Measurement Services in the RMP Program. (i) In order to remain a listed participant, each organization that is listed for primary measurement services in the RMP program on the effective date of this section shall pay an annual fee of $390 for each device. (ii) Each organization seeking listing for primary measurement services that submits an initial application after the effective date of this section shall pay an annual fee of $390 per device. This fee will be prorated quarterly, based on the acceptance date of an organization's application. (iii) Organizations that have or are seeking a listing for secondary measurement services for their primary devices will not be required to pay the additional $50 fee applicable to secondary organizations. (2) Organizations Listed for or Seeking Listing for Secondary Measurement Services in the RMP Program. (i) In order to remain a listed participant, each organization that is listed for secondary measurement services in the RMP program on the effective date of this section shall pay an annual fee of $50 for each business location listed. (ii) Each organization seeking listing for secondary measurement services that submits an initial application after the effective date of this section shall pay an annual fee of $50 for each business location listed. This fee will be prorated quarterly, based on the acceptance date of an organization's application. (iii) Primary organizations that have or are seeking secondary listings for methods other than those for which they are listed as a primary, are subject to the fees. (3) Individual Proficiency Component of the RMP Program. (i) In order to remain a listed participant, each individual listed in the RMP individual proficiency program on the effective date of this section shall pay an annual fee of $105. (ii) Each individual who submits an initial application after the effective date of this section shall pay an annual fee of $105. This fee will be prorated quarterly, based on the acceptance date of an individual's application. (iii) Individuals who have or are seeking listing status as an RMP primary or secondary organization are subject to the applicable fees under paragraphs (a)(1) and (2) of this section. (4) RCP Program. (i)(A) In order to remain a listed participant, each individual listed in the RCP program on the effective date of this section shall pay an annual fee of $210. (B) Each individual who is not a listed participant in the RCP program on the effective date of this section and submits an initial application after the effective date of this section shall pay an annual fee of $210. This fee will be prorated quarterly, based on the acceptance date of an individual's application. (ii) An organization or individual who is not a listed participant in EPA's radon proficiency programs on the effective date of this section and/or whose proficiency program application has not yet been accepted by EPA becomes subject to the fees described above once its application has been accepted by EPA. Fees for such organizations or individuals will be prorated quarterly, based on the acceptance date of the application. To remain listed, each participant in the RMP or RCP programs, whether individual or organization, shall submit the appropriate annual fee to EPA each year. (b) Exemptions. State and local governments are exempted from these fees under section 305(e)(2) of TSCA, 15 U.S.C. 2665. (c) Determination of Fees. (1) Participants listed in the RMP and RCP programs on the effective date of this section will be sent, by EPA, a payment invoice with its fee calculation at least 30 days before the payment is due. Fees will be assessed based on the current information in EPA's proficiency data bases. Participants who intend to pay the invoiced fee amount must send their payment to EPA following the procedures in the invoice. Organizations or individuals who wish to notify EPA of any errors or corrections they wish to make to their listing status must do so by following the instructions on the payment invoice. Corrected payment invoices for both the RMP Program and the RCP Program shall be sent to: Radon Proficiency Programs User Fees, c/o Sanford Cohen and Associates, Inc. (SC&A), 1418 I-85 Parkway, Montgomery, Alabama, 36106. EPA will review the corrections noted on the payment invoice, adjust the payment invoice amount (as appropriate) and issue a new invoice. Participants must pay the amount in the corrected payment invoice within 30 days of the date listed on the corrected invoice. (2) If the appropriate fee or a revised payment invoice for an individual or organization participating in the RMP or RCP program has not been received by EPA on or before the payment due date, EPA will send, by certified mail, notice that the individual or organization will be delisted from the proficiency program unless he/she pays the fee within 30 days of this second certified notification. If payment still has not been received by EPA after 30 days of the second certified notification, the organization's or individual's listing shall be removed from the proficiency program. (3) New or initial applicants to the RMP or RCP programs will be assessed a fee at the time of their initial application. EPA will send a payment invoice to the new applicant upon acceptance of the initial application. The applicant will be given at least 30 days from the date on the payment invoice to remit payment. The fee assessed will be prorated quarterly, based on the acceptance date of the application. If the appropriate fee has not been received by EPA by the payment due date, the application will be placed in an inactive file with no further action taken by EPA. (d) Payment Procedures. Each remittance to EPA under this section shall be in United States currency and shall be paid by certified check, personal or business check, or money order made payable to the order of the “U.S. ENVIRONMENTAL PROTECTION AGENCY” and sent to: U.S. EPA, Washington Financial Management Center, Radon Proficiency Program User Fees (IRAA), P.O. Box 952491, St. Louis, Missouri, 63195-2491. The fee payment shall include the original copy of the EPA payment invoice. Collection of fees will begin in the calendar year beginning January 1, 1995. Specific guidance on how and when fees must be paid can be found in How to Pay Your Radon Proficiency Programs User Fees, U.S. EPA/Office of Radiation and Indoor Air. Copies of this document can be obtained by contacting the RIS at (334) 272-2797 or by FAX at (334) 260-9051. (e) Adjustment of Fees. (1) EPA shall collect 100 percent of its operating costs associated with its radon proficiency programs by calendar year 1998. As necessary, EPA shall adjust the fees established by this subpart each year over the next four years to collect the following percentages of program costs: Actual fees for each fiscal year will be calculated based on program costs and participation rates. New fee schedules will be published in the Federal Register as a technical amendment final rule to this part to become effective 30 days or more after publication. (2) EPA will use a three-step process to adjust the fees annually. First, EPA will estimate the costs of providing each of the proficiency programs for the upcoming year. EPA will account for future additional fixed costs (e.g., updating examinations) and increases/decreases in variable costs due to inflation and other factors. In order to calculate increases/decreases in costs due to inflation, EPA may use one of the three following indices: the Federal General Schedule (GS) pay scale, the Consumer Price Index (CPI), and/or a component of the CPI, such as services. Second, EPA will estimate the number of participants for each program. At a minimum, these participation rates will be based on past and current program participation rates. Third, EPA shall calculate the per capita costs that individuals and organizations should pay to enable it to recover its fixed and variable costs each year for each program. EPA shall also consider potential industry impacts as it adjusts to levels to ultimately achieve full cost recovery over the period of five years." 40:40:27.0.1.1.5.2.9.2,40,Protection of Environment,I,F,195,PART 195—RADON PROFICIENCY PROGRAMS,B,Subpart B—Fees,,§ 195.30 Failure to remit fee.,EPA,,,,"EPA will not process an application or continue a participant's listing in the National Radon Measurement Proficiency program, individual proficiency component of the RMP program, or the National Radon Contractor Proficiency program until the appropriate remittance provided in § 195.20(a) has been received by EPA. Failure by a currently EPA-listed organization or individual to remit the required fees in a timely manner will result in the loss of that organization's or individual's listing status as specified in § 195.20(c)." 46:46:7.0.1.4.28.1.63.1,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.01,Subpart 195.01—Application,,§ 195.01-1 General.,USCG,,,,(a) The provisions of this part shall apply to all vessels except as specifically noted in this part. 46:46:7.0.1.4.28.1.63.2,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.01,Subpart 195.01—Application,,§ 195.01-3 Incorporation by reference.,USCG,,,"[CGD 82-042, 53 FR 17706, May 18, 1988, as amended by CGD 96-041, 61 FR 50735, Sept. 27, 1996; CGD 97-057, 62 FR 51051, Sept. 30, 1997; USCG-1999-5151, 64 FR 67187, Dec. 1, 1999; USCG-2009-0702, 74 FR 49241, Sept. 25, 2009; USCG-2012-0832, 77 FR 59789, Oct. 1, 2012; USCG-2013-0671, 78 FR 60165, Sept. 30, 2013]","(a) Certain materials are incorporated by reference into this part with the approval of the Director of the Federal Register in accordance with 5 U.S.C. 552(a). To enforce any edition other than the one listed in paragraph (b) of this section, notice of the change must be published in the Federal Register and the material made available to the public. All approved material is on file at the Office of the Federal Register, Washington, DC 20408, and at Coast Guard Headquarters. Contact Commandant (CG-ENG), Attn: Office of Design and Engineering Systems, U.S. Coast Guard Stop 7509, 2703 Martin Luther King Jr. Avenue SE., Washington, DC 20593-7509. The material is also available from the source indicated in paragraph (b). (b) The material approved for incorporation by reference in this part, and the sections affected is: 100 Barr Harbor Drive, West Conshohocken, PA 19428-2959. ASTM F 1014-92, Standard Specification for Flashlights on Vessels—195.35-5 100 Barr Harbor Drive, West Conshohocken, PA 19428-2959. ASTM F 1014-92, Standard Specification for Flashlights on Vessels—195.35-5" 46:46:7.0.1.4.28.10.63.1,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.27,Subpart 195.27—Sounding Equipment,,§ 195.27-1 When required.,USCG,,,"[CGFR 67-83, 33 FR 1156, Jan. 27, 1968, as amended by CGD 75-074, 42 FR 5965, Jan. 31, 1977]","(a) All mechanically propelled vessels of 500 gross tons and over shall be fitted with an efficient electronic deep-sea sounding apparatus and another independent means of obtaining deep-sea soundings, which may be a deep-sea hand lead." 46:46:7.0.1.4.28.11.63.1,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.30,Subpart 195.30—Protection From Refrigerants,,§ 195.30-1 Application.,USCG,,,,"(a) This subpart, except § 195.30-90, applies to each vessel that is contracted for on or after November 23, 1992, and is equipped with any refrigeration unit using— (1) Ammonia to refrigerate any space with a volume of more than 20 cubic feet; or (2) Fluorocarbons to refrigerate any space with a volume of more than 1000 cubic feet. (b) Each vessel that is contracted for before November 23, 1992, must satisfy § 195.30-90 if it is equipped with any refrigeration unit using— (1) Ammonia to refrigerate any space with a volume of more than 20 cubic feet, or (2) Fluorocarbons to refrigerate any space with a volume of more than 1000 cubic feet." 46:46:7.0.1.4.28.11.63.2,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.30,Subpart 195.30—Protection From Refrigerants,,§ 195.30-5 General.,USCG,,,,"(a) Each self-contained breathing apparatus must be of the pressure-demand, open-circuit type, approved by the Mine Safety and Health Administration (MSHA) and by the National Institute for Occupational Safety and Health (NIOSH), and have at a minimum a 30-minute air supply, a full facepiece, and a spare charge. (b) All equipment shall be maintained in an operative condition, and it shall be the responsibility of the master and chief engineer to ascertain that a sufficient number of the crew are familiar with the operation of the equipment." 46:46:7.0.1.4.28.11.63.3,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.30,Subpart 195.30—Protection From Refrigerants,,§ 195.30-15 Self-contained breathing apparatus.,USCG,,,,"(a) Each vessel must have a self-contained breathing apparatus for use as protection against gas leaking from a refrigeration unit. (b) The self-contained breathing apparatus required by paragraph (a) of this section may be one of those required by § 195.35-10." 46:46:7.0.1.4.28.11.63.4,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.30,Subpart 195.30—Protection From Refrigerants,,"§ 195.30-90 Vessels contracted for before November 23, 1992.",USCG,,,"[CGD 86-036, 57 FR 48327, Oct. 23, 1992, as amended by CGD 95-028, 62 FR 51220, Sept. 30, 1997]","Vessels contracted for before November 23, 1992, must meet the following requirements: (a) Each vessel must satisfy §§ 195.30-5 through 195.30-15 concerning the number of items and method of stowage of equipment. (b) Items of equipment previously approved, but not meeting the applicable specifications set forth in § 195.30-5, may continue in service as long as they are maintained in good condition to the satisfaction of the Officer in Charge, Marine Inspection; but each item in an installation or a replacement must meet all applicable specifications. (c) Each respirator must either satisfy § 195.30-5(a) or be a self-contained compressed-air breathing apparatus previously approved by MSHA and NIOSH under part 160, subpart 160.011, of this chapter." 46:46:7.0.1.4.28.12.63.1,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.35,Subpart 195.35—Fireman's Outfit,,§ 195.35-1 Application.,USCG,,,"[CGD 86-036, 57 FR 48327, Oct. 23, 1992]","(a) This subpart, except § 195.35-90, applies to each vessel, other than an unmanned barge, contracted for on or after November 23, 1992. (b) Each vessel, other than an unmanned barge, contracted for before November 23, 1992, must satisfy § 195.35-90. (c) All unmanned barges are exempt from the requirements in this subpart. However, if any unmanned barge carries a fireman's outfit, the outfit must meet the requirements in this subpart for such outfits aboard manned barges." 46:46:7.0.1.4.28.12.63.2,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.35,Subpart 195.35—Fireman's Outfit,,§ 195.35-5 General.,USCG,,,"[CGFR 67-83, 33 FR 1156, Jan. 27, 1968, as amended by CGFR 69-72, 34 FR 17504, Oct. 29, 1969; CGD 82-042, 53 FR 17706, May 18, 1988; CGD 86-036, 57 FR 48327, Oct. 23, 1992; USCG-1999-5151, 64 FR 67187, Dec. 1, 1999]","(a) All flame safety lamps shall be of an approved type, constructed in accordance with subpart 160.016 of part 160 of Subchapter Q (Specifications) of this chapter. (b) Each self-contained breathing apparatus must be of the pressure-demand, open-circuit type, approved by the Mine Safety and Health Administration (MSHA) and by the National Institute for Occupational Safety and Health (NIOSH), and have at a minimum a 30-minute air supply and a full facepiece. (c) Flashlights shall be Type II or Type III, constructed and marked in accordance with ASTM F 1014 (incorporated by reference, see § 195.01-3). (d) All lifelines shall be of steel or bronze wire rope. Steel wire rope shall be either inherently corrosion-resistant, or made so by galvanizing or tinning. Each end shall be fitted with a hook with keeper having throat opening which can be readily slipped over a 5/8 -inch bolt. The total length of the lifeline shall be dependent upon the size and arrangement of the vessel, and more than one line may be hooked together to achieve the necessary length. No individual length of lifeline may be less than 50 feet in length. The assembled lifeline shall have a minimum breaking strength of 1,500 pounds. (e) All equipment shall be maintained in an operative condition, and it shall be the responsibility of the master and chief engineer to ascertain that a sufficient number of the crew are familiar with the operation of the equipment. (f) Boots and gloves shall be of rubber or other electrically nonconducting material. (g) The helmet shall provide effective protection against impact. (h) Protective clothing shall be of material that will protect the skin from the heat of fire and burns from scalding steam. The outer surface shall be water resistant." 46:46:7.0.1.4.28.12.63.3,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.35,Subpart 195.35—Fireman's Outfit,,§ 195.35-10 Fireman's outfit.,USCG,,,"[CGFR 69-72, 34 FR 17504, Oct. 29, 1969, as amended by CGD 75-074, 42 FR 5965, Jan. 31, 1977; CGD 86-036, 57 FR 48327, Oct. 23, 1992]","(a) Each fireman's outfit must consist of one self-contained breathing apparatus, one lifeline with a belt or a suitable harness, one flashlight, one flame safety lamp, one rigid helmet, boots and gloves, protective clothing, and one fire ax. (b) Every vessel shall carry at least two fireman's outfits. The fireman's outfits must be stored in widely separated, accessible locations." 46:46:7.0.1.4.28.12.63.4,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.35,Subpart 195.35—Fireman's Outfit,,§ 195.35-15 Stowage.,USCG,,,,"(a) Equipment shall be stowed in a convenient, accessible location as determined by the master, for use in case of emergency." 46:46:7.0.1.4.28.12.63.5,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.35,Subpart 195.35—Fireman's Outfit,,§ 195.35-20 Spare charges.,USCG,,,,"(a) A complete recharge shall be carried for each self-contained breathing apparatus, and a complete set of spare batteries shall be carried for each flashlight. The spares shall be stowed in the same location as the equipment it is to reactivate." 46:46:7.0.1.4.28.12.63.6,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.35,Subpart 195.35—Fireman's Outfit,,"§ 195.35-90 Vessels contracted for before November 23, 1992.",USCG,,,"[CGD 86-036, 57 FR 48327, Oct. 23, 1992, as amended by CGD 95-028, 62 FR 51220, Sept. 30, 1997]","Vessels contracted for before November 23, 1992, must meet the following requirements: (a) Each vessel must satisfy §§ 195.35-5 through 195.35-20 concerning the number of items and method of stowage of equipment. (b) Items of equipment previously approved, but not meeting the applicable specifications set forth in § 195.35-5, may continue in service as long as they are maintained in good condition to the satisfaction of the Officer in Charge, Marine Inspection; but each item in an installation or a replacement must meet all applicable specifications. (c) Each respirator must either satisfy § 195.35-5(b) or be a self-contained compressed-air breathing apparatus previously approved by MSHA and NIOSH under part 160, subpart 160.011, of this chapter." 46:46:7.0.1.4.28.13.63.1,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.40,Subpart 195.40—Pilot Boarding Equipment,,§ 195.40-1 Pilot boarding equipment.,USCG,,,"[CGD 79-032, 49 FR 25455, June 21, 1984, as amended by USCG-2020-0519, 89 FR 76707, Sept. 18, 2024]","(a) This section applies to each vessel that normally embarks or disembarks a pilot from a pilot boat or other vessel. (b) Each vessel must have suitable pilot boarding equipment available for use on each side of the vessel. If a vessel has only one set of equipment, the equipment must be capable of being easily transferred to and rigged for use on either side of the vessel. (c) Pilot boarding equipment must be capable of resting firmly against the vessel's side and be secured so that it is clear from overboard discharges. (d) Each vessel must have lighting positioned to provide adequate illumination for the pilot boarding equipment and each point of access. (e) Each vessel must have a point of access that has— (1) A gateway in the rails or bulwark with adequate handholds; or (2) Two handhold stanchions and a bulwark ladder that is securely attached to the bulwark rail and deck. (f) The pilot boarding equipment required by paragraph (b) of this section must include at least one pilot ladder approved under subpart 163.003 of this chapter. Each pilot ladder must be of a single length and capable of extending from the point of access to the water's edge during each condition of loading and trim, with an adverse list of 15°. (g) Whenever the distance from the water's edge to the point of access is more than 30 feet, access from a pilot ladder to the vessel must be by way of an accommodation ladder or equally safe and convenient means." 46:46:7.0.1.4.28.2.63.1,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.03,Subpart 195.03—Marine Engineering Systems,,§ 195.03-1 Installation and details.,USCG,,,,"(a) The installation of all systems of a marine engineering nature, together with the details of design, construction, and installation, shall be in accordance with the requirements of Subchapter F (Marine Engineering) of this chapter. Systems of this type include the following: Steering Systems. Bilge and Ballast Systems. Tank Vent and Sounding Systems. Overboard Discharges and Shell Connections. Pipe and Pressure Systems. Liquefied Petroleum Gas Systems. Steering Systems. Bilge and Ballast Systems. Tank Vent and Sounding Systems. Overboard Discharges and Shell Connections. Pipe and Pressure Systems. Liquefied Petroleum Gas Systems." 46:46:7.0.1.4.28.3.63.1,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.05,Subpart 195.05—Electrical Engineering and Interior Communications Systems,,§ 195.05-1 Installation and details.,USCG,,,,"(a) The installation of all systems of an electrical engineering or interior communication nature, together with the details of design, construction, and installation shall be in accordance with the requirements of Subchapter J (Electrical Engineering) of this chapter. Systems of this type include the following: Ship's Service Generating Systems. Ship's Service Power Distribution Systems. Ship's Lighting Systems. Electric Propulsion and Propulsion Control Systems. Emergency Lighting and Power Systems. Electric Lifeboat Winch Systems. Electric Steering Gear and Steering Control Systems. Fire Detecting and Alarm Systems. Sound Powered Telephone and Voice Tube Systems. Engine Order Telegraph Systems. Rudder Angle Indicator Systems. Refrigerated Spaces Alarm Systems. Navigation Lights Systems. Daylight Signaling Lights. Miscellaneous Machinery Alarms and Controls. General Alarm Systems. Ship's Service Generating Systems. Ship's Service Power Distribution Systems. Ship's Lighting Systems. Electric Propulsion and Propulsion Control Systems. Emergency Lighting and Power Systems. Electric Lifeboat Winch Systems. Electric Steering Gear and Steering Control Systems. Fire Detecting and Alarm Systems. Sound Powered Telephone and Voice Tube Systems. Engine Order Telegraph Systems. Rudder Angle Indicator Systems. Refrigerated Spaces Alarm Systems. Navigation Lights Systems. Daylight Signaling Lights. Miscellaneous Machinery Alarms and Controls. General Alarm Systems." 46:46:7.0.1.4.28.4.63.1,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.06,Subpart 195.06—Lifesaving Appliances and Arrangements,,§ 195.06-1 Lifesaving appliances and arrangements.,USCG,,,"[CGD 84-069, 61 FR 25312, May 20, 1996]",All lifesaving appliances and arrangements shall be in accordance with the requirements for special purpose vessels in subchapter W (Lifesaving Appliances and Arrangements) of this chapter. 46:46:7.0.1.4.28.5.63.1,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.07,"Subpart 195.07—Anchors, Chains, and Hawsers",,§ 195.07-1 Application.,USCG,,,,"(a) The provisions of this subpart, with the exception of § 195.07-90, shall apply to all vessels other than unmanned barges, contracted for on or after March 1, 1968. (b) Vessels other than unmanned barges contracted for prior to March 1, 1968 shall meet the requirements of § 195.07-90." 46:46:7.0.1.4.28.5.63.2,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.07,"Subpart 195.07—Anchors, Chains, and Hawsers",,"§ 195.07-5 Ocean, coastwise, or Great Lakes service.",USCG,,,"[CGFR 67-83, 33 FR 1156, Jan. 27, 1968, as amended by CGD 87-013, 53 FR 20624, June 6, 1988]","(a) Vessels in ocean, coastwise, or Great Lakes service shall be fitted with anchors, chains, and hawsers which shall be in general agreement with the standards established by the American Bureau of Shipping, see subpart 188.35 of part 188 of this subchapter. (b) In addition to the provisions of paragraph (a) of this section, the following requirements and alternatives also apply: (1) The American Bureau of Shipping rules relating to anchor equipment are mandatory, not a guide. (2) Vessels under 200 feet (61 meters) in length and with an American Bureau of Shipping equipment number of less than 150 may be equipped with either: (i) One anchor of the tabular weight and one-half the tabulated length of anchor chain listed in the applicable standard, or (ii) Two anchors of one-half the tabular weight with the total length of anchor chain listed in the applicable standard provided both anchors are in a position that allows for ready use at all times and the windlass is capable of heaving in either anchor. (c) Standards of other recognized classification societies may be used, in lieu of those established by the American Bureau of Shipping, upon approval by the Commandant." 46:46:7.0.1.4.28.5.63.3,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.07,"Subpart 195.07—Anchors, Chains, and Hawsers",,"§ 195.07-10 Lakes, bays, and sounds, or river service.",USCG,,,,"(a) Vessels in lakes, bays, and sounds, or river service shall be fitted with such ground tackle and hawsers as deemed necessary by the Officer in Charge, Marine Inspection, depending upon the size of the vessel and the waters on which it operates." 46:46:7.0.1.4.28.5.63.4,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.07,"Subpart 195.07—Anchors, Chains, and Hawsers",,"§ 195.07-90 Vessels contracted for prior to March 1, 1968.",USCG,,,,"(a) Vessels contracted for prior to March 1, 1968, shall meet the following requirements: (1) Existing arrangements, materials, installations, and facilities previously accepted or approved shall be considered satisfactory for the same service so long as they are maintained in good condition to the satisfaction of the Officer in Charge, Marine Inspection. If the service of the vessel is changed, the suitability of the equipment will be established by the Officer in Charge, Marine Inspection. (2) Minor repairs, alterations and replacements may be permitted to the same standards as the original installations. However, all new installations, major alterations, or major replacements shall meet the applicable requirements in this subpart for new vessels." 46:46:7.0.1.4.28.6.63.1,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.09,Subpart 195.09—Scientific Equipment,,§ 195.09-1 Application.,USCG,,,,(a) The provisions of this subpart shall apply to all vessels. 46:46:7.0.1.4.28.6.63.2,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.09,Subpart 195.09—Scientific Equipment,,§ 195.09-5 General.,USCG,,,,"(a) All scientific equipment shall be designed to good commercial standards for such appliances, where applicable. Their electrical and pressure connections to the ship's supply shall be designed to marine standards. (b) It shall be the responsibility of the owner to assure that the scientific equipment and their electrical or pressure connections to the ship's supply are maintained in such a manner as to be free of personnel hazards which may be caused by shock, temperature extremes, and moving parts." 46:46:7.0.1.4.28.7.63.1,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.11,Subpart 195.11—Portable Vans and Tanks,,§ 195.11-1 Application.,USCG,,,,(a) The provisions of this subpart shall apply to all vessels. 46:46:7.0.1.4.28.7.63.2,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.11,Subpart 195.11—Portable Vans and Tanks,,§ 195.11-5 Scope.,USCG,,,,"(a) The provisions in this subpart contain requirements for the design, construction, and stowage of portable vans, or tanks, which may be carried on board vessels. As used in this subpart, portable vans and tanks, are intended to include those temporary structures which may be carried aboard a vessel for a limited period of time and which are not permanently attached to the vessel. (b) Special consideration may be given to the approval of portable structures which have been used for other purposes prior to proposed use on these vessels. (c) As used in this subpart, portable vans, magazines, chests, etc., are intended to include those temporary structures which may be carried aboard a vessel for a limited period of time and which are not permanently attached to the vessel. The use, arrangement, and handling of such portable structures shall be approved by the Officer in Charge, Marine Inspection, prior to placement on board the vessel." 46:46:7.0.1.4.28.7.63.3,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.11,Subpart 195.11—Portable Vans and Tanks,,§ 195.11-10 Design and construction of portable vans.,USCG,,,,"(a) The design and material selection shall incorporate consideration of forces and environmental conditions to which the structure, attachments, and attachment points will be exposed. (b) Steel, aluminum or other substantial material suitable for a marine environment may be used for construction of the basic van box. (c) Accommodation vans are those intended to provide increased accommodation and related spaces of a temporary nature aboard a vessel. They shall, insofar as is reasonable and practicable, meet the applicable requirements of this subchapter for means of escape, arrangement, interior construction, and electrical installations. (d) Power vans are those outfitted with electrical power generating machinery or batteries providing electrical power for other vans or to scientific equipment. They shall insofar as is reasonable and practicable meet the applicable requirements of this subchapter for pressure piping, electrical, fire extinguishing and ventilation systems. (e) Vans for the use or storage of chemical stores as defined in § 194.05-3 of this subchapter shall be constructed and outfitted in accordance with the applicable requirements of this subchapter. (f) Vans containing scientific equipment are considered as within the definition of § 188.10-67 of this subchapter." 46:46:7.0.1.4.28.7.63.4,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.11,Subpart 195.11—Portable Vans and Tanks,,§ 195.11-15 Plan approval and inspection.,USCG,,,"[CGFR 67-83, 33 FR 1156, Jan. 27, 1968, as amended by USCG-1999-4976, 65 FR 6510, Feb. 9, 2000]","(a) Accommodation, power and chemical stores vans are subject to normal plan submission procedures of subpart 189.55 and to initial construction inspection. They must be inspected at each inspection for certification and periodic inspection. (b) Vans which have not undergone plan review and initial inspection may be accepted on a single voyage basis by the OCMI provided that they are in good condition and are free of hazards to personnel." 46:46:7.0.1.4.28.7.63.5,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.11,Subpart 195.11—Portable Vans and Tanks,,§ 195.11-20 Marking and label plate.,USCG,,,,"(a) All vans shall be provided with a label plate stating light weight, gross weight, and power requirements where applicable. (b) For vans subject to inspection label plates shall provide space for the date of initial inspection, the marine inspector's initials, and stamp. Space shall also be provided for the reinspection stamping." 46:46:7.0.1.4.28.7.63.6,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.11,Subpart 195.11—Portable Vans and Tanks,,§ 195.11-25 Loading and stowage.,USCG,,,,"(a) Vans required to be inspected and bearing a current inspection stamp may be accepted for loading and stowage by the master of the vessel who shall insure that the van is in good condition. (1) Vans containing scientific equipment and nonhazardous stores may be accepted by the master of the vessel subject to his inspection to determine that electrical and pressure connections are in good condition and adequate for the service intended. (b) The master shall insure that all vans are securely stowed and attached to the vessel to prevent shifting in a seaway. Portable vans to be occupied during the vessel's operation shall be securely attached to the vessel by welding, bolting, or equivalent means. (c) Vans shall be located with due regard to access and to prevent recirculation of the discharge from the exhaust systems of the vessel. (d) The loading of vans shall be in accordance with the stability requirements of the vessel. (e) Prior to a vessel's departure, an entry shall be made in the official logbook for each portable van placed on board that such van and its stowage are in compliance with the applicable requirements in this subchapter." 46:46:7.0.1.4.28.7.63.7,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.11,Subpart 195.11—Portable Vans and Tanks,,§ 195.11-30 Portable tanks.,USCG,,,"[CGFR 67-83, 33 FR 1156, Jan. 27, 1968, as amended by CGD 86-033, 53 FR 36027, Sept. 16, 1988]","(a) All portable tanks, whether hazardous or nonhazardous commodities, shall be loaded and stowed in accordance with the stability requirements of the vessel. (b) Portable tanks for flammable or combustible liquids in bulk (see § 188.05-30(b) of this subchapter) shall not be carried on vessels. (c) Portable tanks containing other hazardous materials shall be in accordance with the requirements of 49 CFR parts 171-179." 46:46:7.0.1.4.28.8.63.1,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.17,Subpart 195.17—Radar,,§ 195.17-1 When required.,USCG,,,"[CGD 75-074, 42 FR 5965, Jan. 31, 1977]","All mechanically propelled vessels of 1,600 gross tons and over in ocean or coastwise service must be fitted with a marine radar system for surface navigation. Facilities for plotting radar readings must be provided on the bridge." 46:46:7.0.1.4.28.9.63.1,46,Shipping,I,U,195,PART 195—VESSEL CONTROL AND MISCELLANEOUS SYSTEMS AND EQUIPMENT,195.19,Subpart 195.19—Magnetic Compass and Gyrocompass,,§ 195.19-1 When required.,USCG,,,"[CGD 75-074, 42 FR 5965, Jan. 31, 1977]","(a) All mechanically propelled vessels in ocean or coastwise service must be fitted with a magnetic compass. (b) All mechanically propelled vessels of 1,600 gross tons and over in ocean or coastwise service must be fitted with a gyrocompass in addition to the magnetic compass. (c) Each vessel must have an illuminated repeater for the gyrocompass required under paragraph (b) that is at the main steering stand unless the gyrocompass is illuminated and is at the main steering stand." 49:49:3.1.1.2.11.1.20.1,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,A,Subpart A—General,,§ 195.0 Scope.,PHMSA,,,"[Amdt. 195-45, 56 FR 26925, June 12, 1991]",This part prescribes safety standards and reporting requirements for pipeline facilities used in the transportation of hazardous liquids or carbon dioxide. 49:49:3.1.1.2.11.1.20.10,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,A,Subpart A—General,,§ 195.10 Responsibility of operator for compliance with this part.,PHMSA,,,,"An operator may make arrangements with another person for the performance of any action required by this part. However, the operator is not thereby relieved from the responsibility for compliance with any requirement of this part." 49:49:3.1.1.2.11.1.20.11,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,A,Subpart A—General,,§ 195.11 What is a regulated rural gathering line and what requirements apply?,PHMSA,,,"[73 FR 31644, June 3, 2008, as amended by Amdt. 195-105, 87 FR 20987, Apr. 8, 2022; Amdt. 195-106, 88 FR 50062, Aug. 1, 2023]","Each operator of a regulated rural gathering line, as defined in paragraph (a) of this section, must comply with the safety requirements described in paragraph (b) of this section. (a) Definition. As used in this section, a regulated rural gathering line means an onshore gathering line in a rural area that meets all of the following criteria— (1) Has a nominal diameter from 6 5/8 inches (168 mm) to 8 5/8 inches (219.1 mm); (2) Is located in or within one-quarter mile (.40 km) of an unusually sensitive area as defined in § 195.6; and (3) Operates at a maximum pressure established under § 195.406 corresponding to— (i) A stress level greater than 20-percent of the specified minimum yield strength of the line pipe; or (ii) If the stress level is unknown or the pipeline is not constructed with steel pipe, a pressure of more than 125 psi (861 kPa) gage. (b) Safety requirements. Each operator must prepare, follow, and maintain written procedures to carry out the requirements of this section. Except for the requirements in paragraphs (b)(2), (b)(3), (b)(9) and (b)(10) of this section, the safety requirements apply to all materials of construction. (1) Identify all segments of pipeline meeting the criteria in paragraph (a) of this section before April 3, 2009. (2) For steel pipelines constructed, replaced, relocated, or otherwise changed after July 3, 2009: (i) Design, install, construct, initially inspect, and initially test the pipeline in compliance with this part, unless the pipeline is converted under § 195.5. (ii) [Reserved] (3) For non-steel pipelines constructed after July 3, 2009, notify the Administrator according to § 195.8. (4) Beginning no later than January 3, 2009, comply with the reporting requirements in subpart B of this part. (5) Establish the maximum operating pressure of the pipeline according to § 195.406 before transportation begins, or if the pipeline exists on July 3, 2008, before July 3, 2009. (6) Install line markers according to § 195.410 before transportation begins, or if the pipeline exists on July 3, 2008, before July 3, 2009. Continue to maintain line markers in compliance with § 195.410. (7) Establish a continuing public education program in compliance with § 195.440 before transportation begins, or if the pipeline exists on July 3, 2008, before January 3, 2010. Continue to carry out such program in compliance with § 195.440. (8) Establish a damage prevention program in compliance with § 195.442 before transportation begins, or if the pipeline exists on July 3, 2008, before July 3, 2009. Continue to carry out such program in compliance with § 195.442. (9) For steel pipelines, comply with subpart H of this part, except corrosion control is not required for pipelines existing on July 3, 2008 before July 3, 2011. (10) For steel pipelines, establish and follow a comprehensive and effective program to continuously identify operating conditions that could contribute to internal corrosion. The program must include measures to prevent and mitigate internal corrosion, such as cleaning the pipeline and using inhibitors. This program must be established before transportation begins or if the pipeline exists on July 3, 2008, before July 3, 2009. (11) To comply with the Operator Qualification program requirements in subpart G of this part, have a written description of the processes used to carry out the requirements in § 195.505 to determine the qualification of persons performing operations and maintenance tasks. These processes must be established before transportation begins or if the pipeline exists on July 3, 2008, before July 3, 2009. (c) New unusually sensitive areas. If, after July 3, 2008, a new unusually sensitive area is identified and a segment of pipeline becomes regulated as a result, except for the requirements of paragraphs (b)(9) and (b)(10) of this section, the operator must implement the requirements in paragraphs (b)(2) through (b)(11) of this section for the affected segment within 6 months of identification. For steel pipelines, comply with the deadlines in paragraph (b)(9) and (b)(10). (d) Record Retention. An operator must maintain records demonstrating compliance with each requirement according to the following schedule. (1) An operator must maintain the segment identification records required in paragraph (b)(1) of this section and the records required to comply with (b)(10) of this section, for the life of the pipe. (2) An operator must maintain the records necessary to demonstrate compliance with each requirement in paragraphs (b)(2) through (b)(9), and (b)(11) of this section according to the record retention requirements of the referenced section or subpart." 49:49:3.1.1.2.11.1.20.12,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,A,Subpart A—General,,§ 195.12 What requirements apply to low-stress pipelines in rural areas?,PHMSA,,,"[76 FR 25587, May 5, 2011, as amended at 76 FR 43605, July 21, 2011]","(a) General. This Section sets forth the requirements for each category of low-stress pipeline in a rural area set forth in paragraph (b) of this Section. This Section does not apply to a rural low-stress pipeline regulated under this Part as a low-stress pipeline that crosses a waterway currently used for commercial navigation; these pipelines are regulated pursuant to § 195.1(a)(2). (b) Categories. An operator of a rural low-stress pipeline must meet the applicable requirements and compliance deadlines for the category of pipeline set forth in paragraph (c) of this Section. For purposes of this Section, a rural low-stress pipeline is a Category 1, 2, or 3 pipeline based on the following criteria: (1) A Category 1 rural low-stress pipeline: (i) Has a nominal diameter of 8 5/8 inches (219.1 mm) or more; (ii) Is located in or within one-half mile (.80 km) of an unusually sensitive area (USA) as defined in § 195.6; and (iii) Operates at a maximum pressure established under § 195.406 corresponding to: (A) A stress level equal to or less than 20-percent of the specified minimum yield strength of the line pipe; or (B) If the stress level is unknown or the pipeline is not constructed with steel pipe, a pressure equal to or less than 125 psi (861 kPa) gauge. (2) A Category 2 rural pipeline: (i) Has a nominal diameter of less than 8 5/8 inches (219.1mm); (ii) Is located in or within one-half mile (.80 km) of an unusually sensitive area (USA) as defined in § 195.6; and (iii) Operates at a maximum pressure established under § 195.406 corresponding to: (A) A stress level equal to or less than 20-percent of the specified minimum yield strength of the line pipe; or (B) If the stress level is unknown or the pipeline is not constructed with steel pipe, a pressure equal to or less than 125 psi (861 kPa) gage. (3) A Category 3 rural low-stress pipeline: (i) Has a nominal diameter of any size and is not located in or within one-half mile (.80 km) of an unusually sensitive area (USA) as defined in § 195.6; and (ii) Operates at a maximum pressure established under § 195.406 corresponding to a stress level equal to or less than 20-percent of the specified minimum yield strength of the line pipe; or (iii) If the stress level is unknown or the pipeline is not constructed with steel pipe, a pressure equal to or less than 125 psi (861 kPa) gage. (c) Applicable requirements and deadlines for compliance. An operator must comply with the following compliance dates depending on the category of pipeline determined by the criteria in paragraph (b): (1) An operator of a Category 1 pipeline must: (i) Identify all segments of pipeline meeting the criteria in paragraph (b)(1) of this Section before April 3, 2009. (ii) Beginning no later than January 3, 2009, comply with the reporting requirements of Subpart B for the identified segments. (iii) IM requirements— (A) Establish a written program that complies with § 195.452 before July 3, 2009, to assure the integrity of the pipeline segments. Continue to carry out such program in compliance with § 195.452. (B) An operator may conduct a determination per § 195.452(a) in lieu of the one-half mile buffer. (C) Complete the baseline assessment of all segments in accordance with § 195.452(c) before July 3, 2015, and complete at least 50-percent of the assessments, beginning with the highest risk pipe, before January 3, 2012. (iv) Comply with all other safety requirements of this Part, except Subpart H, before July 3, 2009. Comply with the requirements of Subpart H before July 3, 2011. (2) An operator of a Category 2 pipeline must: (i) Identify all segments of pipeline meeting the criteria in paragraph (b)(2) of this Section before July 1, 2012. (ii) Beginning no later than January 3, 2009, comply with the reporting requirements of Subpart B for the identified segments. (iii) IM— (A) Establish a written IM program that complies with § 195.452 before October 1, 2012 to assure the integrity of the pipeline segments. Continue to carry out such program in compliance with § 195.452. (B) An operator may conduct a determination per § 195.452(a) in lieu of the one-half mile buffer. (C) Complete the baseline assessment of all segments in accordance with § 195.452(c) before October 1, 2016 and complete at least 50-percent of the assessments, beginning with the highest risk pipe, before April 1, 2014. (iv) Comply with all other safety requirements of this Part, except Subpart H, before October 1, 2012. Comply with Subpart H of this Part before October 1, 2014. (3) An operator of a Category 3 pipeline must: (i) Identify all segments of pipeline meeting the criteria in paragraph (b)(3) of this Section before July 1, 2012. (ii) Beginning no later than January 3, 2009, comply with the reporting requirements of Subpart B for the identified segments. (A)(iii) Comply with all safety requirements of this Part, except the requirements in § 195.452, Subpart B, and the requirements in Subpart H, before October 1, 2012. Comply with Subpart H of this Part before October 1, 2014. (d) Economic compliance burden. (1) An operator may notify PHMSA in accordance with § 195.452(m) of a situation meeting the following criteria: (i) The pipeline is a Category 1 rural low-stress pipeline; (ii) The pipeline carries crude oil from a production facility; (iii) The pipeline, when in operation, operates at a flow rate less than or equal to 14,000 barrels per day; and (iv) The operator determines it would abandon or shut-down the pipeline as a result of the economic burden to comply with the assessment requirements in § 195.452(d) or 195.452(j). (2) A notification submitted under this provision must include, at minimum, the following information about the pipeline: its operating, maintenance and leak history; the estimated cost to comply with the integrity assessment requirements (with a brief description of the basis for the estimate); the estimated amount of production from affected wells per year, whether wells will be shut in or alternate transportation used, and if alternate transportation will be used, the estimated cost to do so. (3) When an operator notifies PHMSA in accordance with paragraph (d)(1) of this Section, PHMSA will stay compliance with §§ 195.452(d) and 195.452(j)(3) until it has completed an analysis of the notification. PHMSA will consult the Department of Energy, as appropriate, to help analyze the potential energy impact of loss of the pipeline. Based on the analysis, PHMSA may grant the operator a special permit to allow continued operation of the pipeline subject to alternative safety requirements. (e) Changes in unusually sensitive areas. (1) If, after June 3, 2008, for Category 1 rural low-stress pipelines or October 1, 2011 for Category 2 rural low-stress pipelines, an operator identifies a new USA that causes a segment of pipeline to meet the criteria in paragraph (b) of this Section as a Category 1 or Category 2 rural low-stress pipeline, the operator must: (i) Comply with the IM program requirement in paragraph (c)(1)(iii)(A) or (c)(2)(iii)(A) of this Section, as appropriate, within 12 months following the date the area is identified regardless of the prior categorization of the pipeline; and (ii) Complete the baseline assessment required by paragraph (c)(1)(iii)(C) or (c)(2)(iii)(C) of this Section, as appropriate, according to the schedule in § 195.452(d)(3). (2) If a change to the boundaries of a USA causes a Category 1 or Category 2 pipeline segment to no longer be within one-half mile of a USA, an operator must continue to comply with paragraph (c)(1)(iii) or paragraph (c)(2)(iii) of this section, as applicable, with respect to that segment unless the operator determines that a release from the pipeline could not affect the USA. (f) Record Retention. An operator must maintain records demonstrating compliance with each requirement applicable to the category of pipeline according to the following schedule. (1) An operator must maintain the segment identification records required in paragraph (c)(1)(i), (c)(2)(i) or (c)(3)(i) of this Section for the life of the pipe. (2) Except for the segment identification records, an operator must maintain the records necessary to demonstrate compliance with each applicable requirement set forth in paragraph (c) of this section according to the record retention requirements of the referenced section or subpart." 49:49:3.1.1.2.11.1.20.13,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,A,Subpart A—General,,§ 195.13 What requirements apply to pipelines transporting hazardous liquids by gravity?,PHMSA,,,"[Amdt. 195-102, 84 FR 52294, Oct. 1, 2019]","(a) Scope. Pipelines transporting hazardous liquids by gravity must comply with the reporting requirements of subpart B of this part. (b) Implementation period —(1) Annual reporting. Comply with the annual reporting requirements in subpart B of this part by March 31, 2021. (2) Accident and safety-related reporting. Comply with the accident and safety-related condition reporting requirements in subpart B of this part by January 1, 2021. (c) Exceptions. (1) This section does not apply to the transportation of a hazardous liquid in a gravity line that meets the definition of a low-stress pipeline, travels no farther than 1 mile from a facility boundary, and does not cross any waterways used for commercial navigation. (2) The reporting requirements in §§ 195.52, 195.61, and 195.65 do not apply to the transportation of a hazardous liquid in a gravity line. (3) The drug and alcohol testing requirements in part 199 of this subchapter do not apply to the transportation of a hazardous liquid in a gravity line." 49:49:3.1.1.2.11.1.20.14,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,A,Subpart A—General,,§ 195.15 What requirements apply to reporting-regulated-only gathering lines?,PHMSA,,,"[Amdt. 195-102, 84 FR 52294, Oct. 1, 2019]","(a) Scope. Gathering lines that do not otherwise meet the definition of a regulated rural gathering line in § 195.11 and any gathering line not already covered under § 195.1(a)(1), (2), (3) or (4) must comply with the reporting requirements of subpart B of this part. (b) Implementation period —(1) Annual reporting. Operators must comply with the annual reporting requirements in subpart B of this part by March 31, 2021. (2) Accident and safety-related condition reporting. Operators must comply with the accident and safety-related condition reporting requirements in subpart B of this part by January 1, 2021. (c) Exceptions. (1) This section does not apply to those gathering lines that are otherwise excepted under § 195.1(b)(3), (7), (8), (9), or (10). (2) The reporting requirements in §§ 195.52, 195.61, and 195.65 do not apply to the transportation of a hazardous liquid in a gathering line that is specified in paragraph (a) of this section. (3) The drug and alcohol testing requirements in part 199 of this subchapter do not apply to the transportation of a hazardous liquid in a gathering line that is specified in paragraph (a) of this section." 49:49:3.1.1.2.11.1.20.15,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,A,Subpart A—General,,§ 195.18 How to notify PHMSA.,PHMSA,,,"[Amdt. 195-105, 87 FR 20987, Apr. 8, 2022]","(a) An operator must provide any notification required by this part by: (1) Sending the notification by electronic mail to InformationResourcesManager@dot.gov; or (2) Sending the notification by mail to ATTN: Information Resources Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New Jersey Ave. SE, Washington, DC 20590. (b) An operator must also notify the appropriate State or local pipeline safety authority when an applicable pipeline segment is located in a State where OPS has an interstate agent agreement, or an intrastate pipeline segment is regulated by that State. (c) Unless otherwise specified, if an operator submits, pursuant to § 195.258, § 195.260, § 195.418, § 195.419, § 195.420 or § 195.452 a notification requesting use of a different integrity assessment method, analytical method, sampling approach, compliance timeline, or technique (e.g., “other technology” or “alternative equivalent technology”) than otherwise prescribed in those sections, that notification must be submitted to PHMSA for review at least 90 days in advance of using that other method, approach, compliance timeline, or technique. An operator may proceed to use the other method, approach, compliance timeline, or technique 91 days after submittal of the notification unless it receives a letter from the Associate Administrator of Pipeline Safety informing the operator that PHMSA objects to the proposal, or that PHMSA requires additional time and/or information to conduct its review." 49:49:3.1.1.2.11.1.20.2,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,A,Subpart A—General,,§ 195.1 Which pipelines are covered by this Part?,PHMSA,,,,"(a) Covered. Except for the pipelines listed in paragraph (b) of this Section, this Part applies to pipeline facilities and the transportation of hazardous liquids or carbon dioxide associated with those facilities in or affecting interstate or foreign commerce, including pipeline facilities on the Outer Continental Shelf (OCS). Covered pipelines include, but are not limited to: (1) Any pipeline that transports a highly volatile liquid; (2) Any pipeline segment that crosses a waterway currently used for commercial navigation; (3) Except for a gathering line not covered by paragraph (a)(4) of this Section, any pipeline located in a rural or non-rural area of any diameter regardless of operating pressure; (4) Any of the following onshore gathering lines used for transportation of petroleum: (i) A pipeline located in a non-rural area; (ii) A regulated rural gathering line as provided in § 195.11; or (iii) A pipeline located in an inlet of the Gulf of America as provided in § 195.413. (5) For purposes of the reporting requirements in subpart B of this part, any gathering line not already covered under paragraphs (a)(1), (2), (3) or (4) of this section. (b) Excepted. This Part does not apply to any of the following: (1) Transportation of a hazardous liquid transported in a gaseous state; (2) Except for the reporting requirements of subpart B of this part, see § 195.13, transportation of a hazardous liquid through a pipeline by gravity. (3) Transportation of a hazardous liquid through any of the following low-stress pipelines: (i) A pipeline subject to safety regulations of the U.S. Coast Guard; or (ii) A pipeline that serves refining, manufacturing, or truck, rail, or vessel terminal facilities, if the pipeline is less than one mile long (measured outside facility grounds) and does not cross an offshore area or a waterway currently used for commercial navigation; (4) Except for the reporting requirements of subpart B of this part, see § 195.15, transportation of petroleum through an onshore rural gathering line that does not meet the definition of a “regulated rural gathering line” as provided in § 195.11. This exception does not apply to gathering lines in the inlets of the Gulf of America subject to § 195.413. (5) Transportation of hazardous liquid or carbon dioxide in an offshore pipeline in state waters where the pipeline is located upstream from the outlet flange of the following farthest downstream facility: The facility where hydrocarbons or carbon dioxide are produced or the facility where produced hydrocarbons or carbon dioxide are first separated, dehydrated, or otherwise processed; (6) Transportation of hazardous liquid or carbon dioxide in a pipeline on the OCS where the pipeline is located upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator; (7) A pipeline segment upstream (generally seaward) of the last valve on the last production facility on the OCS where a pipeline on the OCS is producer-operated and crosses into state waters without first connecting to a transporting operator's facility on the OCS. Safety equipment protecting PHMSA-regulated pipeline segments is not excluded. A producing operator of a segment falling within this exception may petition the Administrator, under § 190.9 of this chapter, for approval to operate under PHMSA regulations governing pipeline design, construction, operation, and maintenance; (8) Transportation of hazardous liquid or carbon dioxide through onshore production (including flow lines), refining, or manufacturing facilities or storage or in-plant piping systems associated with such facilities; (9) Transportation of hazardous liquid or carbon dioxide: (i) By vessel, aircraft, tank truck, tank car, or other non-pipeline mode of transportation; or (ii) Through facilities located on the grounds of a materials transportation terminal if the facilities are used exclusively to transfer hazardous liquid or carbon dioxide between non-pipeline modes of transportation or between a non-pipeline mode and a pipeline. These facilities do not include any device and associated piping that are necessary to control pressure in the pipeline under § 195.406(b); or (10) Transportation of carbon dioxide downstream from the applicable following point: (i) The inlet of a compressor used in the injection of carbon dioxide for oil recovery operations, or the point where recycled carbon dioxide enters the injection system, whichever is farther upstream; or (ii) The connection of the first branch pipeline in the production field where the pipeline transports carbon dioxide to an injection well or to a header or manifold from which a pipeline branches to an injection well. (c) Breakout tanks. Breakout tanks that are subject to this part must comply with requirements that apply specifically to breakout tanks and, to the extent applicable, with requirements that apply to pipeline systems and pipeline facilities. If a conflict exists between a requirement that applies specifically to breakout tanks and a requirement that applies to pipeline systems or pipeline facilities, the requirement that applies specifically to breakout tanks prevails. Anhydrous ammonia breakout tanks need not comply with §§ 195.132(b); 195.205(b); 195.264(b) and (e); 195.307; 195.428(c) through (d); and 195.432(b) and (c)." 49:49:3.1.1.2.11.1.20.3,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,A,Subpart A—General,,§ 195.2 Definitions.,PHMSA,,,"[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982]","As used in this part— Abandoned means permanently removed from service. Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate. Alarm means an audible or visible means of indicating to the controller that equipment or processes are outside operator-defined, safety-related parameters. Barrel means a unit of measurement equal to 42 U.S. standard gallons. Breakout tank means a tank used to (a) relieve surges in a hazardous liquid pipeline system or (b) receive and store hazardous liquid transported by a pipeline for reinjection and continued transportation by pipeline. Carbon dioxide means a fluid consisting of more than 90 percent carbon dioxide molecules compressed to a supercritical state. Component means any part of a pipeline which may be subjected to pump pressure including, but not limited to, pipe, valves, elbows, tees, flanges, and closures. Computation Pipeline Monitoring (CPM) means a software-based monitoring tool that alerts the pipeline dispatcher of a possible pipeline operating anomaly that may be indicative of a commodity release. Confirmed Discovery means when it can be reasonably determined, based on information available to the operator at the time a reportable event has occurred, even if only based on a preliminary evaluation. Control room means an operations center staffed by personnel charged with the responsibility for remotely monitoring and controlling a pipeline facility. Controller means a qualified individual who remotely monitors and controls the safety-related operations of a pipeline facility via a SCADA system from a control room, and who has operational authority and accountability for the remote operational functions of the pipeline facility. Corrosive product means “corrosive material” as defined by § 173.136 Class 8-Definitions of this chapter. Entirely replaced onshore hazardous liquid or carbon dioxide pipeline segments, for the purposes of §§ 195.258, 195.260, and 195.418, means where 2 or more miles of pipe, in the aggregate, have been replaced within any 5 contiguous miles within any 24-month period. This definition does not apply to any gathering line. Exposed underwater pipeline means an underwater pipeline where the top of the pipe protrudes above the underwater natural bottom (as determined by recognized and generally accepted practices) in waters less than 15 feet (4.6 meters) deep, as measured from mean low water. Flammable product means “flammable liquid” as defined by § 173.120 Class 3-Definitions of this chapter. Gathering line means a pipeline 219.1 mm (8 5/8 in) or less nominal outside diameter that transports petroleum from a production facility. Gulf of America and its inlets means the waters from the mean high water mark of the coast of the Gulf of America and its inlets open to the sea (excluding rivers, tidal marshes, lakes, and canals) seaward to include the territorial sea and Outer Continental Shelf to a depth of 15 feet (4.6 meters), as measured from the mean low water. Hazard to navigation means, for the purposes of this part, a pipeline where the top of the pipe is less than 12 inches (305 millimeters) below the underwater natural bottom (as determined by recognized and generally accepted practices) in waters less than 15 feet (4.6 meters) deep, as measured from the mean low water. Hazardous liquid means petroleum, petroleum products, anhydrous ammonia, and ethanol or other non-petroleum fuel, including biofuel, which is flammable, toxic, or would be harmful to the environment if released in significant quantities. Highly volatile liquid or HVL means a hazardous liquid which will form a vapor cloud when released to the atmosphere and which has a vapor pressure exceeding 276 kPa (40 psia) at 37.8 °C (100 °F). In-Line Inspection (ILI) means the inspection of a pipeline from the interior of the pipe using an in-line inspection tool. Also called intelligent or smart pigging. In-Line Inspection Tool or Instrumented Internal Inspection Device means a device or vehicle that uses a non-destructive testing technique to inspect the pipeline from the inside. Also known as intelligent or smart pig. In-plant piping system means piping that is located on the grounds of a plant and used to transfer hazardous liquid or carbon dioxide between plant facilities or between plant facilities and a pipeline or other mode of transportation, not including any device and associated piping that are necessary to control pressure in the pipeline under § 195.406(b). Interstate pipeline means a pipeline or that part of a pipeline that is used in the transportation of hazardous liquids or carbon dioxide in interstate or foreign commerce. Intrastate pipeline means a pipeline or that part of a pipeline to which this part applies that is not an interstate pipeline. Line section means a continuous run of pipe between adjacent pressure pump stations, between a pressure pump station and terminal or breakout tanks, between a pressure pump station and a block valve, or between adjacent block valves. Low-stress pipeline means a hazardous liquid pipeline that is operated in its entirety at a stress level of 20 percent or less of the specified minimum yield strength of the line pipe. Maximum operating pressure (MOP) means the maximum pressure at which a pipeline or segment of a pipeline may be normally operated under this part. Nominal wall thickness means the wall thickness listed in the pipe specifications. Notification of potential rupture means the notification to, or observation by, an operator of indicia identified in § 195.417 of a potential unintentional or uncontrolled release of a large volume of commodity from a pipeline. This definition does not apply to any gathering line. Offshore means beyond the line of ordinary low water along that portion of the coast of the United States that is in direct contact with the open seas and beyond the line marking the seaward limit of inland waters. Operator means a person who owns or operates pipeline facilities. Outer Continental Shelf means all submerged lands lying seaward and outside the area of lands beneath navigable waters as defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control. Person means any individual, firm, joint venture, partnership, corporation, association, State, municipality, cooperative association, or joint stock association, and includes any trustee, receiver, assignee, or personal representative thereof. Petroleum means crude oil, condensate, natural gasoline, natural gas liquids, and liquefied petroleum gas. Petroleum product means flammable, toxic, or corrosive products obtained from distilling and processing of crude oil, unfinished oils, natural gas liquids, blend stocks and other miscellaneous hydrocarbon compounds. Pipe or line pipe means a tube, usually cylindrical, through which a hazardous liquid or carbon dioxide flows from one point to another. Pipeline or pipeline system means all parts of a pipeline facility through which a hazardous liquid or carbon dioxide moves in transportation, including, but not limited to, line pipe, valves, and other appurtenances connected to line pipe, pumping units, fabricated assemblies associated with pumping units, metering and delivery stations and fabricated assemblies therein, and breakout tanks. Pipeline facility means new and existing pipe, rights-of-way and any equipment, facility, or building used in the transportation of hazardous liquids or carbon dioxide. Production facility means piping or equipment used in the production, extraction, recovery, lifting, stabilization, separation or treating of petroleum or carbon dioxide, or associated storage or measurement. (To be a production facility under this definition, piping or equipment must be used in the process of extracting petroleum or carbon dioxide from the ground or from facilities where CO 2 is produced, and preparing it for transportation by pipeline. This includes piping between treatment plants which extract carbon dioxide, and facilities utilized for the injection of carbon dioxide for recovery operations.) Rupture-mitigation valve (RMV) means an automatic shut-off valve (ASV) or a remote-control valve (RCV) that a pipeline operator uses to minimize the volume of hazardous liquid or carbon dioxide released from the pipeline and to mitigate the consequences of a rupture. This definition does not apply to any gathering line. Rural area means outside the limits of any incorporated or unincorpated city, town, village, or any other designated residential or commercial area such as a subdivision, a business or shopping center, or community development. Significant Stress Corrosion Cracking means a stress corrosion cracking (SCC) cluster in which the deepest crack, in a series of interacting cracks, is greater than 10% of the wall thickness and the total interacting length of the cracks is equal to or greater than 75% of the critical length of a 50% through-wall flaw that would fail at a stress level of 110% of SMYS. Specified minimum yield strength means the minimum yield strength, expressed in p.s.i. (kPa) gage, prescribed by the specification under which the material is purchased from the manufacturer. Stress level means the level of tangential or hoop stress, usually expressed as a percentage of specified minimum yield strength. Supervisory Control and Data Acquisition (SCADA) system means a computer-based system or systems used by a controller in a control room that collects and displays information about a pipeline facility and may have the ability to send commands back to the pipeline facility. Surge pressure means pressure produced by a change in velocity of the moving stream that results from shutting down a pump station or pumping unit, closure of a valve, or any other blockage of the moving stream. Toxic product means “poisonous material” as defined by § 173.132 Class 6, Division 6.1-Definitions of this chapter. Unusually Sensitive Area (USA) means a drinking water or ecological resource area that is unusually sensitive to environmental damage from a hazardous liquid pipeline release, as identified under § 195.6. Welder means a person who performs manual or semi-automatic welding. Welding operator means a person who operates machine or automatic welding equipment." 49:49:3.1.1.2.11.1.20.4,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,A,Subpart A—General,,§ 195.3 What documents are incorporated by reference partly or wholly in this part?,PHMSA,,,"[Amdt. 195-117, 90 FR 40764, Aug. 21, 2025]","(a) Certain material is incorporated by reference into this part with the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. All approved incorporation by reference material (IBR) is available for inspection at the Pipeline and Hazardous Materials Safety Administration (PHMSA) and the National Archives and Records Administration (NARA). Contact PHSMA at: Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE, Washington, DC 20590; phone: 202-366-4046; website: www.phmsa.dot.gov/pipeline/regs. For information on the availability of this material at NARA, visit www.archives.gov/federal-register/cfr/ibr-locations or email fr.inspection@nara.gov. The material may be obtained from the sources in the following paragraphs of this section. (b) American Petroleum Institute (API), 200 Massachusetts Avenue NW, Suite 1100, Washington, DC 20001-5571; phone: (202) 682-8000; website: www.api.org/. (1) API 510, Pressure Vessel Inspection Code: In-service Inspection, Rating, Repair, and Alteration, 10th Edition, May 2014, Including Addendum 1 (May 2017); IBR approved for §§ 195.205(b); 195.432(c). (2) API Recommended Practice 5L1, Recommended Practice for Railroad Transportation of Line Pipe, 7th edition, September 2009, (API RP 5L1); IBR approved for § 195.207(a). (3) API Recommended Practice 5LT, Recommended Practice for Truck Transportation of Line Pipe, First edition, March 12, 2012, (API RP 5LT); IBR approved for § 195.207(c). (4) API Recommended Practice 5LW, Recommended Practice Transportation of Line Pipe on Barges and Marine Vessels, 3rd edition, September 2009, (API RP 5LW); IBR approved for § 195.207(b). (5) API Recommended Practice 651, Cathodic Protection of Aboveground Petroleum Storage Tanks, 4th edition, September 2014, (API RP 651); IBR approved for §§ 195.565; 195.573(d). (6) API Recommended Practice 652, Linings of Aboveground Petroleum Storage Tank Bottoms, 5th Edition, May 2020, (API RP 652); IBR approved for § 195.579(d). (7) API Recommended Practice 1130, Computational Pipeline Monitoring for Liquids: Pipeline Segment, 3rd edition, September 2007, (API RP 1130); IBR approved for §§ 195.134(c); 195.444(c). (8) API Recommended Practice 1162, Public Awareness Programs for Pipeline Operators, 1st edition, December 2003, (API RP 1162); IBR approved for § 195.440(a), (b), and (c). (9) API Recommended Practice 1165, Recommended Practice for Pipeline SCADA Displays, First edition, January 2007, (API RP 1165); IBR approved for § 195.446(c). (10) API Recommended Practice 1168, Pipeline Control Room Management, First edition, September 2008, (API RP 1168); IBR approved for § 195.446(c) and (f). (11) API Recommended Practice 2003, Protection Against Ignitions Arising out of Static, Lightning, and Stray Currents, 8th Edition, September 2015, reaffirmed March 2020, (API RP 2003); IBR approved for § 195.405(a). (12) API Recommended Practice 2026, Safe Access/Egress Involving Floating Roofs of Storage Tanks in Petroleum Service, 4th edition, July 2022, (API RP 2026); IBR approved for § 195.405(b). (13) API Specification 5L, Line Pipe, 46th edition, April 2018, including Errata 1 (May 2018), (API Spec 5L); IBR approved for § 195.106(b) and (e). (14) API Specification 6D, Specification for Valves, 25th edition, November 1, 2021, including Errata 1 (December 2021), Errata 2 (April 2022), Errata 3 (October 2023), Addendum 1 (April 2023), Addendum 2 (September 2024), and Addendum 3 (March 2025), (API Spec 6D); IBR approved for § 195.116(d). (15) API Specification 12F, Specification for Shop-welded Tanks for Storage of Production Liquids, 13th Edition, January 2019, (API Spec 12F); IBR approved for §§ 195.132(b); 195.205(b); 195.264(e); 195.307(a); 195.565; 195.579(d). (16) API Standard 620, Design and Construction of Large, Welded, Low-pressure Storage Tanks, 12th edition, effective October 2013, including Addendum 1 through 4 (November 2014), Addendum 2 (April 2018), Addendum 3 (March 2021), Addendum 4 (February 2025), Errata 1 (March 2025), (API Std 620); IBR approved for §§ 195.132(b); 195.205(b); 195.264(e); 195.307(b); 195.565; 195.579(d). (17) API Standard 650, Welded Tanks for Oil Storage, 13th edition, March 2020, including Errata 1 (January 2021), (API Std 650); IBR approved for §§ 195.132(b); 195.205(b); 195.307(c); 195.565; 195.579(d). (18) API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction, 3rd edition, December 2001, (including addendum 1 (September 2003), addendum 2 (November 2005), addendum 3 (February 2008), and errata (April 2008)), (API Std 653); IBR approved for §§ 195.205(b); 195.307(d); 195.432(b). (19) API Standard 1104, Welding of Pipelines and Related Facilities, 21st edition, September 2013, including Errata 1 through 5 (April 2014 through September 2018), Addendum 1 (July 2014), and Addendum 2 (May 2016), (API Std 1104); IBR approved for §§ 195.214(a); 195.222(a) and (b); 195.228(b). (20) API Standard 1163, In-Line Inspection Systems Qualification, Second edition, April 2013, (API Std 1163); IBR approved for § 195.591. (21) API Standard 2000, Venting Atmospheric and Low-pressure Storage Tanks, 7th Edition, March 2014, Reaffirmed April 2020, (API Std 2000); IBR approved for § 195.264(e). (22) API Standard 2350, Overfill Prevention for Storage Tanks in Petroleum Facilities, 5th edition, September 2020, including Errata 1 (April 2021), (API Std 2350); IBR approved for § 195.428(c). (23) API Standard 2510, Design and Construction of LPG Installations, 9th Edition, August 2020, (API Std 2510); IBR approved for §§ 195.132(b); 195.205(b); 195.264(b) and (e); 195.307(e); 195.428(c); 195.432(c). (c) American Society of Mechanical Engineers (ASME), Two Park Avenue, New York, NY 10016; phone: (800) 843-2763 (U.S/Canada); website: www.asme.org/. (1) ASME/ANSI B16.9-2007, Factory-Made Wrought Buttwelding Fittings, December 7, 2007, (ASME/ANSI B16.9); IBR approved for § 195.118(a). (2) ASME/ANSI B31G-1991 (Reaffirmed 2004), Manual for Determining the Remaining Strength of Corroded Pipelines, 2004, (ASME/ANSI B31G); IBR approved for §§ 195.452(h); 195.587; 195.588(c). (3) ASME B31.4-2019, Pipeline Transportation Systems for Liquids and Slurries: ASME Code for Pressure Piping, B31, issued November 1, 2019, (ASME B31.4); IBR approved for § 195.110(a). (4) ASME B31.8-2018, Gas Transmission and Distribution Piping Systems, Issued November 20, 2018, (ASME B31.8); IBR approved for §§ 195.5(a); 195.406(a). (5) ASME Boiler & Pressure Vessel Code, Section VIII, Division 1, Rules for Construction of Pressure Vessels, 2007 edition, July 1, 2007, (ASME BPVC, Section VIII, Division 1); IBR approved for §§ 195.124; 195.307(e). (6) ASME Boiler & Pressure Vessel Code, Section VIII, Division 2, Alternate Rules, Rules for Construction of Pressure Vessels, 2007 edition, July 1, 2007, (ASME BPVC, Section VIII, Division 2); IBR approved for § 195.307(e). (7) ASME Boiler & Pressure Vessel Code, Section IX: Qualification Standard for Welding and Brazing Procedures, Welders, Brazers, and Welding and Brazing Operators, 2007 edition, July 1, 2007, (ASME BPVC, Section IX); IBR approved for § 195.222(a). (d) American Society for Nondestructive Testing (ASNT), 1201 Dublin Road, Suite #G04, Columbus, OH 43215; phone: (800) 222-2768; website: www.asnt.org. (1) ANSI/ASNT ILI-PQ-2017, In-line Inspection Personnel Qualification and Certification, 2017 Edition, approved December 12, 2017, (ASNT ILI-PQ); IBR approved for § 195.591. (2) [Reserved] (e) Association for Material Protection and Performance (AMPP) (formerly NACE), 1440 South Creek Drive, Houston, TX 77084; phone: (281) 228-6223 or (800) 797-6223; website: www.ampp.org /. (1) NACE SP0102-2017, In-Line Inspection of Pipelines, March 10, 2017, (NACE SP0102); IBR approved for §§ 195.120(a); 195.591. (2) NACE SP0169-2007, Standard Practice, Control of External Corrosion on Underground or Submerged Metallic Piping Systems, reaffirmed March 15, 2007, (NACE SP0169), IBR approved for §§ 195.571; 195.573(a). (3) NACE SP0204-2015, Stress Corrosion Cracking (SCC) Direct Assessment Methodology, Revised March 14, 2015, (NACE SP0204); IBR approved for § 195.588(c). (4) ANSI/NACE SP0502-2010, Pipeline External Corrosion Direct Assessment Methodology, revised June 24, 2010, (NACE SP0502); IBR approved for § 195.588(b). (f) ASTM International, 100 Barr Harbor Drive, P.O. Box C700, West Conshohocken, PA 19428; phone: (610) 832-9585; website: www.astm.org/. (1) ASTM A53/A53M-22, Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded and Seamless, approved July 1, 2022, (ASTM A53/A53M); IBR approved for § 195.106(e). (2) ASTM A106/A106M-19A, Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service, approved November 1, 2019, (ASTM A106/A106M); IBR approved for § 195.106(e). (3) ASTM A333/A333M-18, Standard Specification for Seamless and Welded Steel Pipe for Low-Temperature Service and Other Applications with Required Notch Toughness, approved November 1, 2018, (ASTM A333/A333M); IBR approved for § 195.106(e). (4) ASTM A381/A381M-23, Standard Specification for Metal-Arc-Welded Carbon or High-Strength Low-alloy Steel Pipe for Use With High-Pressure Transmission Systems, approved November 1, 2023, (ASTM A381/A381M); IBR approved for § 195.106(e). (5) ASTM A671/A671M-20, Standard Specification for Electric-Fusion-Welded Steel Pipe for Atmospheric and Lower Temperatures, approved March 1, 2020, (ASTM A671/A671M); IBR approved for § 195.106(e). (6) ASTM A672/A672M-19, Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures, approved November 1, 2019, (ASTM A672/672M); IBR approved for § 195.106(e). (7) ASTM A691/A691M-19, Standard Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for High-Pressure Service at High Temperatures, approved November 1, 2019, (ASTM A691/A691M); IBR approved for § 195.106(e). (g) Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS), 127 Park St. NE, Vienna, VA 22180; phone: (703) 281-6613; website: www.mss-hq.org/. (1) MSS SP-75-2019 Standard Practice, High-Strength, Wrought, Butt-Welding Fittings, published December 2019, (MSS SP-75); IBR approved for § 195.118(a). (2) [Reserved] (h) National Fire Protection Association (NFPA), 1 Batterymarch Park, Quincy, MA 02169; phone: (800) 344-3555; website: www.nfpa.org/. (1) NFPA 30, Flammable and Combustible Liquids Code, 2021 Edition, effective August 31, 2020; IBR approved for § 195.264(b). (2) [Reserved] (i) Pipeline Research Council International, Inc. (PRCI), 15059 Conference Center Drive Suite 130, Chantilly, VA 20151; phone: (703) 205-1600; website: www.prci.org. (1) AGA Pipeline Research Committee, Project PR-3-805, A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe, December 22, 1989, (PR-3-805 (RSTRENG)); IBR approved for §§ 195.452(h); 195.587; 195.588(c). (2) [Reserved]" 49:49:3.1.1.2.11.1.20.5,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,A,Subpart A—General,,§ 195.4 Compatibility necessary for transportation of hazardous liquids or carbon dioxide.,PHMSA,,,"[Amdt. 195-45, 56 FR 26925, June 12, 1991]","No person may transport any hazardous liquid or carbon dioxide unless the hazardous liquid or carbon dioxide is chemically compatible with both the pipeline, including all components, and any other commodity that it may come into contact with while in the pipeline." 49:49:3.1.1.2.11.1.20.6,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,A,Subpart A—General,,§ 195.5 Conversion to service subject to this part.,PHMSA,,,"[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 59 FR 33396, June 28, 1994; Amdt. 195-173, 66 FR 67004, Dec. 27, 2001; Amdt. 195-99, 80 FR 184, Jan. 5, 2015; Amdt. 195-101, 82 FR 7999, Jan. 23, 2017; Amdts. 192-135, 195-107, 89 FR 33284, Apr. 29, 2024]","(a) A steel pipeline previously used in service not subject to this part qualifies for use under this part if the operator prepares and follows a written procedure to accomplish the following: (1) The design, construction, operation, and maintenance history of the pipeline must be reviewed and, where sufficient historical records are not available, appropriate tests must be performed to determine if the pipeline is in satisfactory condition for safe operation. If one or more of the variables necessary to verify the design pressure under § 195.106 or to perform the testing under paragraph (a)(4) of this section is unknown, the design pressure may be verified and the maximum operating pressure determined by— (i) Testing the pipeline in accordance with ASME B31.8 (incorporated by reference, see § 195.3), Appendix N, to produce a stress equal to the yield strength; and (ii) Applying, to not more than 80 percent of the first pressure that produces a yielding, the design factor F in § 195.106(a) and the appropriate factors in § 195.106(e). (2) The pipeline right-of-way, all aboveground segments of the pipeline, and appropriately selected underground segments must be visually inspected for physical defects and operating conditions which reasonably could be expected to impair the strength or tightness of the pipeline. (3) All known unsafe defects and conditions must be corrected in accordance with this part. (4) The pipeline must be tested in accordance with subpart E of this part to substantiate the maximum operating pressure permitted by § 195.406. (b) A pipeline that qualifies for use under this section need not comply with the corrosion control requirements of subpart H of this part until 12 months after it is placed into service, notwithstanding any previous deadlines for compliance. (c) Each operator must keep for the life of the pipeline a record of the investigations, tests, repairs, replacements, and alterations made under the requirements of paragraph (a) of this section. (d) An operator converting a pipeline from service not previously covered by this part must notify PHMSA 60 days before the conversion occurs as required by § 195.64." 49:49:3.1.1.2.11.1.20.7,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,A,Subpart A—General,,§ 195.6 Unusually Sensitive Areas (USAs).,PHMSA,,,"[Amdt. 195-71, 65 FR 80544, Dec. 21, 2000, as amended at 86 FR 73186, Dec. 27, 2021]","As used in this part, a USA means a drinking water or ecological resource area that is unusually sensitive to environmental damage from a hazardous liquid pipeline release. (a) An USA drinking water resource is: (1) The water intake for a Community Water System (CWS) or a Non-transient Non-community Water System (NTNCWS) that obtains its water supply primarily from a surface water source and does not have an adequate alternative drinking water source; (2) The Source Water Protection Area (SWPA) for a CWS or a NTNCWS that obtains its water supply from a Class I or Class IIA aquifer and does not have an adequate alternative drinking water source. Where a state has not yet identified the SWPA, the Wellhead Protection Area (WHPA) will be used until the state has identified the SWPA; or (3) The sole source aquifer recharge area where the sole source aquifer is a karst aquifer in nature. (b) An USA ecological resource is: (1) An area containing a critically imperiled species or ecological community; (2) A multi-species assemblage area; (3) A migratory waterbird concentration area; (4) An area containing an imperiled species, threatened or endangered species, depleted marine mammal species, or an imperiled ecological community where the species or community is aquatic, aquatic dependent, or terrestrial with a limited range; (5) An area containing an imperiled species, threatened or endangered species, depleted marine mammal species, or imperiled ecological community where the species or community occurrence is considered to be one of the most viable, highest quality, or in the best condition, as identified by an element occurrence ranking (EORANK) of A (excellent quality) or B (good quality) or (6) A coastal beach; or (7) Certain coastal waters. (c) Definitions used in this part— Adequate Alternative Drinking Water Source means a source of water that currently exists, can be used almost immediately with a minimal amount of effort and cost, involves no decline in water quality, and will meet the consumptive, hygiene, and fire fighting requirements of the existing population of impacted customers for at least one month for a surface water source of water and at least six months for a groundwater source. Aquatic or Aquatic Dependent Species or Community means a species or community that primarily occurs in aquatic, marine, or wetland habitats, as well as species that may use terrestrial habitats during all or some portion of their life cycle, but that are still closely associated with or dependent upon aquatic, marine, or wetland habitats for some critical component or portion of their life-history ( i.e., reproduction, rearing and development, feeding, etc). Class I Aquifer means an aquifer that is surficial or shallow, permeable, and is highly vulnerable to contamination. Class I aquifers include: (1) Unconsolidated Aquifers (Class Ia) that consist of surficial, unconsolidated, and permeable alluvial, terrace, outwash, beach, dune and other similar deposits. These aquifers generally contain layers of sand and gravel that, commonly, are interbedded to some degree with silt and clay. Not all Class Ia aquifers are important water-bearing units, but they are likely to be both permeable and vulnerable. The only natural protection of these aquifers is the thickness of the unsaturated zone and the presence of fine-grained material; (2) Soluble and Fractured Bedrock Aquifers (Class Ib). Lithologies in this class include limestone, dolomite, and, locally, evaporitic units that contain documented karst features or solution channels, regardless of size. Generally these aquifers have a wide range of permeability. Also included in this class are sedimentary strata, and metamorphic and igneous (intrusive and extrusive) rocks that are significantly faulted, fractured, or jointed. In all cases groundwater movement is largely controlled by secondary openings. Well yields range widely, but the important feature is the potential for rapid vertical and lateral ground water movement along preferred pathways, which result in a high degree of vulnerability; (3) Semiconsolidated Aquifers (Class Ic) that generally contain poorly to moderately indurated sand and gravel that is interbedded with clay and silt. This group is intermediate to the unconsolidated and consolidated end members. These systems are common in the Tertiary age rocks that are exposed throughout the Gulf and Atlantic coastal states. Semiconsolidated conditions also arise from the presence of intercalated clay and caliche within primarily unconsolidated to poorly consolidated units, such as occurs in parts of the High Plains Aquifer; or (4) Covered Aquifers (Class Id) that are any Class I aquifer overlain by less than 50 feet of low permeability, unconsolidated material, such as glacial till, lacustrian, and loess deposits. Certain coastal waters means the territorial sea of the United States; the Great Lakes and their connecting waters; and the marine and estuarine waters of the United States up to the head of tidal influence. Class IIa aquifer means a Higher Yield Bedrock Aquifer that is consolidated and is moderately vulnerable to contamination. These aquifers generally consist of fairly permeable sandstone or conglomerate that contain lesser amounts of interbedded fine grained clastics (shale, siltstone, mudstone) and occasionally carbonate units. In general, well yields must exceed 50 gallons per minute to be included in this class. Local fracturing may contribute to the dominant primary porosity and permeability of these systems. Coastal beach means any land between the high- and low-water marks of certain coastal waters. Community Water System (CWS) means a public water system that serves at least 15 service connections used by year-round residents of the area or regularly serves at least 25 year-round residents. Critically imperiled species or ecological community (habitat) means an animal or plant species or an ecological community of extreme rarity, based on The Nature Conservancy's Global Conservation Status Rank. There are generally 5 or fewer occurrences, or very few remaining individuals (less than 1,000) or acres (less than 2,000). These species and ecological communities are extremely vulnerable to extinction due to some natural or man-made factor. Depleted marine mammal species means a species that has been identified and is protected under the Marine Mammal Protection Act of 1972, as amended (MMPA) (16 U.S.C. 1361 et seq. ). The term “depleted” refers to marine mammal species that are listed as threatened or endangered, or are below their optimum sustainable populations (16 U.S.C. 1362). The term “marine mammal” means “any mammal which is morphologically adapted to the marine environment (including sea otters and members of the orders Sirenia, Pinnipedia, and Cetacea), or primarily inhabits the marine environment (such as the polar bear)” (16 U.S.C. 1362). The order Sirenia includes manatees, the order Pinnipedia includes seals, sea lions, and walruses, and the order Cetacea includes dolphins, porpoises, and whales. Ecological community means an interacting assemblage of plants and animals that recur under similar environmental conditions across the landscape. Element occurrence rank (EORANK) means the condition or viability of a species or ecological community occurrence, based on a population's size, condition, and landscape context. EORANKs are assigned by the Natural Heritage Programs. An EORANK of A means an excellent quality and an EORANK of B means good quality. Imperiled species or ecological community (habitat) means a rare species or ecological community, based on The Nature Conservancy's Global Conservation Status Rank. There are generally 6 to 20 occurrences, or few remaining individuals (1,000 to 3,000) or acres (2,000 to 10,000). These species and ecological communities are vulnerable to extinction due to some natural or man-made factor. Karst aquifer means an aquifer that is composed of limestone or dolomite where the porosity is derived from connected solution cavities. Karst aquifers are often cavernous with high rates of flow. Migratory waterbird concentration area means a designated Ramsar site or a Western Hemisphere Shorebird Reserve Network site. Multi-species assemblage area means an area where three or more different critically imperiled or imperiled species or ecological communities, threatened or endangered species, depleted marine mammals, or migratory waterbird concentrations co-occur. Non-transient Non-community Water System (NTNCWS) means a public water system that regularly serves at least 25 of the same persons over six months per year. Examples of these systems include schools, factories, and hospitals that have their own water supplies. Public Water System (PWS) means a system that provides the public water for human consumption through pipes or other constructed conveyances, if such system has at least 15 service connections or regularly serves an average of at least 25 individuals daily at least 60 days out of the year. These systems include the sources of the water supplies— i.e., surface or ground. PWS can be community, non-transient non-community, or transient non-community systems. Ramsar site means a site that has been designated under The Convention on Wetlands of International Importance Especially as Waterfowl Habitat program. Ramsar sites are globally critical wetland areas that support migratory waterfowl. These include wetland areas that regularly support 20,000 waterfowl; wetland areas that regularly support substantial numbers of individuals from particular groups of waterfowl, indicative of wetland values, productivity, or diversity; and wetland areas that regularly support 1% of the individuals in a population of one species or subspecies of waterfowl. Sole source aquifer (SSA) means an area designated by the U.S. Environmental Protection Agency under the Sole Source Aquifer program as the “sole or principal” source of drinking water for an area. Such designations are made if the aquifer's ground water supplies 50% or more of the drinking water for an area, and if that aquifer were to become contaminated, it would pose a public health hazard. A sole source aquifer that is karst in nature is one composed of limestone where the porosity is derived from connected solution cavities. They are often cavernous, with high rates of flow. Source Water Protection Area (SWPA) means the area delineated by the state for a public water supply system (PWS) or including numerous PWSs, whether the source is ground water or surface water or both, as part of the state source water assessment program (SWAP) approved by EPA under section 1453 of the Safe Drinking Water Act. Species means species, subspecies, population stocks, or distinct vertebrate populations. Terrestrial ecological community with a limited range means a non-aquatic or non-aquatic dependent ecological community that covers less than five (5) acres. Terrestrial species with a limited range means a non-aquatic or non-aquatic dependent animal or plant species that has a range of no more than five (5) acres. Threatened and endangered species (T&E) means an animal or plant species that has been listed and is protected under the Endangered Species Act of 1973, as amended (ESA73) (16 U.S.C. 1531 et seq.). “Endangered species” is defined as “any species which is in danger of extinction throughout all or a significant portion of its range” (16 U.S.C. 1532). “Threatened species” is defined as “any species which is likely to become an endangered species within the foreseeable future throughout all or a significant portion of its range” (16 U.S.C. 1532). Transient Non-community Water System (TNCWS) means a public water system that does not regularly serve at least 25 of the same persons over six months per year. This type of water system serves a transient population found at rest stops, campgrounds, restaurants, and parks with their own source of water. Wellhead Protection Area (WHPA) means the surface and subsurface area surrounding a well or well field that supplies a public water system through which contaminants are likely to pass and eventually reach the water well or well field. Western Hemisphere Shorebird Reserve Network (WHSRN) site means an area that contains migratory shorebird concentrations and has been designated as a hemispheric reserve, international reserve, regional reserve, or endangered species reserve. Hemispheric reserves host at least 500,000 shorebirds annually or 30% of a species flyway population. International reserves host 100,000 shorebirds annually or 15% of a species flyway population. Regional reserves host 20,000 shorebirds annually or 5% of a species flyway population. Endangered species reserves are critical to the survival of endangered species and no minimum number of birds is required." 49:49:3.1.1.2.11.1.20.8,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,A,Subpart A—General,,§ 195.8 Transportation of hazardous liquid or carbon dioxide in pipelines constructed with other than steel pipe.,PHMSA,,,"[Amdt. 195-45, 56 FR 26925, June 12, 1991, as amended by Amdt. 195-50, 59 FR 17281, Apr. 12, 1994]","No person may transport any hazardous liquid or carbon dioxide through a pipe that is constructed after October 1, 1970, for hazardous liquids or after July 12, 1991 for carbon dioxide of material other than steel unless the person has notified the Administrator in writing at least 90 days before the transportation is to begin. The notice must state whether carbon dioxide or a hazardous liquid is to be transported and the chemical name, common name, properties and characteristics of the hazardous liquid to be transported and the material used in construction of the pipeline. If the Administrator determines that the transportation of the hazardous liquid or carbon dioxide in the manner proposed would be unduly hazardous, he will, within 90 days after receipt of the notice, order the person that gave the notice, in writing, not to transport the hazardous liquid or carbon dioxide in the proposed manner until further notice." 49:49:3.1.1.2.11.1.20.9,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,A,Subpart A—General,,§ 195.9 Outer continental shelf pipelines.,PHMSA,,,"[Amdt. 195-59, 62 FR 61695, Nov. 19, 1997, as amended at 70 FR 11140, Mar. 8, 2005]","Operators of transportation pipelines on the Outer Continental Shelf must identify on all their respective pipelines the specific points at which operating responsibility transfers to a producing operator. For those instances in which the transfer points are not identifiable by a durable marking, each operator will have until September 15, 1998 to identify the transfer points. If it is not practicable to durably mark a transfer point and the transfer point is located above water, the operator must depict the transfer point on a schematic maintained near the transfer point. If a transfer point is located subsea, the operator must identify the transfer point on a schematic which must be maintained at the nearest upstream facility and provided to PHMSA upon request. For those cases in which adjoining operators have not agreed on a transfer point by September 15, 1998 the Regional Director and the MMS Regional Supervisor will make a joint determination of the transfer point." 49:49:3.1.1.2.11.2.20.1,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,B,"Subpart B—Annual, Accident, and Safety-Related Condition Reporting",,§ 195.48 Scope.,PHMSA,,,"[76 FR 25588, May 5, 2011]",This Subpart prescribes requirements for periodic reporting and for reporting of accidents and safety-related conditions. This Subpart applies to all pipelines subject to this Part. An operator of a Category 3 rural low-stress pipeline meeting the criteria in § 195.12 is not required to complete those parts of the hazardous liquid annual report form PHMSA F 7000-1.1 associated with IM or high consequence areas. 49:49:3.1.1.2.11.2.20.10,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,B,"Subpart B—Annual, Accident, and Safety-Related Condition Reporting",,§ 195.60 Operator assistance in investigation.,PHMSA,,,,"If the Department of Transportation investigates an accident, the operator involved shall make available to the representative of the Department all records and information that in any way pertain to the accident, and shall afford all reasonable assistance in the investigation of the accident." 49:49:3.1.1.2.11.2.20.11,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,B,"Subpart B—Annual, Accident, and Safety-Related Condition Reporting",,§ 195.61 National Pipeline Mapping System.,PHMSA,,,"[Amdt. 195-100, 80 FR 12780, Mar. 11, 2015]","(a) Each operator of a hazardous liquid pipeline facility must provide the following geospatial data to PHMSA for that facility: (1) Geospatial data, attributes, metadata and transmittal letter appropriate for use in the National Pipeline Mapping System. Acceptable formats and additional information are specified in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or by contacting the PHMSA Geographic Information Systems Manager at (202) 366-4595. (2) The name of and address for the operator. (3) The name and contact information of a pipeline company employee, to be displayed on a public Web site, who will serve as a contact for questions from the general public about the operator's NPMS data. (b) This information must be submitted each year, on or before June 15, representing assets as of December 31 of the previous year. If no changes have occurred since the previous year's submission, the operator must refer to the information provided in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or contact the PHMSA Geographic Information Systems Manager at (202) 366-4595." 49:49:3.1.1.2.11.2.20.12,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,B,"Subpart B—Annual, Accident, and Safety-Related Condition Reporting",,§ 195.63 OMB control number assigned to information collection.,PHMSA,,,"[Amdt. 195-95, 75 FR 72907, Nov. 26, 2010]","The control numbers assigned by the Office of Management and Budget to the hazardous liquid pipeline information collection pursuant to the Paperwork Reduction Act are 2137-0047, 2137-0601, 2137-0604, 2137-0605, 2137-0618, and 2137-0622." 49:49:3.1.1.2.11.2.20.13,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,B,"Subpart B—Annual, Accident, and Safety-Related Condition Reporting",,§ 195.64 National Registry of Operators.,PHMSA,,,"[Amdt. 195-95, 75 FR 72907, Nov. 26, 2010, as amended by Amdt. 195-100, 80 FR 12780, Mar. 11, 2015; Amdt. 195-101, 82 FR 7999, Jan. 23, 2017; Amdt. 195-103, 85 FR 8127, Feb. 12, 2020]","(a) OPID Request. Effective January 1, 2012, each operator of a hazardous liquid or carbon dioxide pipeline or pipeline facility must obtain from PHMSA an Operator Identification Number (OPID). An OPID is assigned to an operator for the pipeline or pipeline system for which the operator has primary responsibility. To obtain an OPID or a change to an OPID, an operator must complete an OPID Assignment Request DOT Form PHMSA F 1000.1 through the National Registry of Operators in accordance with § 195.58. (b) OPID validation. An operator who has already been assigned one or more OPID by January 1, 2011 must validate the information associated with each such OPID through the National Registry of Operators at https://portal.phmsa.dot.gov, and correct that information as necessary, no later than June 30, 2012. (c) Changes. Each operator must notify PHMSA electronically through the National Registry of Operators at https://portal.phmsa.dot.gov, of certain events. (1) An operator must notify PHMSA of any of the following events not later than 60 days before the event occurs: (i) Construction or any planned rehabilitation, replacement, modification, upgrade, uprate, or update of a facility, other than a section of line pipe, that costs $10 million or more. If 60 day notice is not feasible because of an emergency, an operator must notify PHMSA as soon as practicable; (ii) Construction of 10 or more miles of a new or replacement hazardous liquid or carbon dioxide pipeline; (iii) Reversal of product flow direction when the reversal is expected to last more than 30 days. This notification is not required for pipeline systems already designed for bi-directional flow; or (iv) A pipeline converted for service under § 195.5, or a change in commodity as reported on the annual report as required by § 195.49. (2) An operator must notify PHMSA of any following event not later than 60 days after the event occurs: (i) A change in the primary entity responsible ( i.e. , with an assigned OPID) for managing or administering a safety program required by this part covering pipeline facilities operated under multiple OPIDs. (ii) A change in the name of the operator; (iii) A change in the entity (e.g., company, municipality) responsible for operating an existing pipeline, pipeline segment, or pipeline facility; (iv) The acquisition or divestiture of 50 or more miles of pipeline or pipeline system subject to this part; or (v) The acquisition or divestiture of an existing pipeline facility subject to this part. (d) Reporting. An operator must use the OPID issued by PHMSA for all reporting requirements covered under this subchapter and for submissions to the National Pipeline Mapping System." 49:49:3.1.1.2.11.2.20.14,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,B,"Subpart B—Annual, Accident, and Safety-Related Condition Reporting",,§ 195.65 Safety data sheets.,PHMSA,,,"[Amdt. 195-102, 84 FR 52294, Oct. 1, 2019]","(a) Each owner or operator of a hazardous liquid pipeline facility, following an accident involving a pipeline facility that results in a hazardous liquid spill, must provide safety data sheets on any spilled hazardous liquid to the designated Federal On-Scene Coordinator and appropriate State and local emergency responders within 6 hours of a telephonic or electronic notice of the accident to the National Response Center. (b) Definitions. In this section: (1) Federal On-Scene Coordinator. The term “Federal On-Scene Coordinator” has the meaning given such term in section 311(a) of the Federal Water Pollution Control Act (33 U.S.C. 1321(a)). (2) National Response Center. The term “National Response Center” means the center described under 40 CFR 300.125(a). (3) Safety data sheet. The term “safety data sheet” means a safety data sheet required under 29 CFR 1910.1200." 49:49:3.1.1.2.11.2.20.2,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,B,"Subpart B—Annual, Accident, and Safety-Related Condition Reporting",,§ 195.49 Annual report.,PHMSA,,,"[75 FR 72907, Nov. 26, 2010]","Each operator must annually complete and submit DOT Form PHMSA F 7000-1.1 for each type of hazardous liquid pipeline facility operated at the end of the previous year. An operator must submit the annual report by June 15 each year, except that for the 2010 reporting year the report must be submitted by August 15, 2011. A separate report is required for crude oil, HVL (including anhydrous ammonia), petroleum products, carbon dioxide pipelines, and fuel grade ethanol pipelines. For each state a pipeline traverses, an operator must separately complete those sections on the form requiring information to be reported for each state." 49:49:3.1.1.2.11.2.20.3,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,B,"Subpart B—Annual, Accident, and Safety-Related Condition Reporting",,§ 195.50 Reporting accidents.,PHMSA,,,"[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-39, 53 FR 24950, July 1, 1988; Amdt. 195-45, 56 FR 26925, June 12, 1991; Amdt. 195-52, 59 FR 33396, June 28, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998; Amdt. 195-75, 67 FR 836, Jan. 8, 2002]","An accident report is required for each failure in a pipeline system subject to this part in which there is a release of the hazardous liquid or carbon dioxide transported resulting in any of the following: (a) Explosion or fire not intentionally set by the operator. (b) Release of 5 gallons (19 liters) or more of hazardous liquid or carbon dioxide, except that no report is required for a release of less than 5 barrels (0.8 cubic meters) resulting from a pipeline maintenance activity if the release is: (1) Not otherwise reportable under this section; (2) Not one described in § 195.52(a)(4); (3) Confined to company property or pipeline right-of-way; and (4) Cleaned up promptly; (c) Death of any person; (d) Personal injury necessitating hospitalization; (e) Estimated property damage, including cost of clean-up and recovery, value of lost product, and damage to the property of the operator or others, or both, exceeding $50,000." 49:49:3.1.1.2.11.2.20.4,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,B,"Subpart B—Annual, Accident, and Safety-Related Condition Reporting",,§ 195.52 Immediate notice of certain accidents.,PHMSA,,,"[75 FR 72907, Nov. 26, 2010, as amended by Amdt. 195-101, 82 FR 7999, Jan. 23, 2017]","(a) Notice requirements. At the earliest practicable moment following discovery, of a release of the hazardous liquid or carbon dioxide transported resulting in an event described in § 195.50, but no later than one hour after confirmed discovery, the operator of the system must give notice, in accordance with paragraph (b) of this section of any failure that: (1) Caused a death or a personal injury requiring hospitalization; (2) Resulted in either a fire or explosion not intentionally set by the operator; (3) Caused estimated property damage, including cost of cleanup and recovery, value of lost product, and damage to the property of the operator or others, or both, exceeding $50,000; (4) Resulted in pollution of any stream, river, lake, reservoir, or other similar body of water that violated applicable water quality standards, caused a discoloration of the surface of the water or adjoining shoreline, or deposited a sludge or emulsion beneath the surface of the water or upon adjoining shorelines; or (5) In the judgment of the operator was significant even though it did not meet the criteria of any other paragraph of this section. (b) Information required. Each notice required by paragraph (a) of this section must be made to the National Response Center either by telephone to 800-424-8802 (in Washington, DC, 202-267-2675) or electronically at http://www.nrc.uscg.mil and must include the following information: (1) Name, address and identification number of the operator. (2) Name and telephone number of the reporter. (3) The location of the failure. (4) The time of the failure. (5) The fatalities and personal injuries, if any. (6) Initial estimate of amount of product released in accordance with paragraph (c) of this section. (7) All other significant facts known by the operator that are relevant to the cause of the failure or extent of the damages. (c) Calculation. A pipeline operator must have a written procedure to calculate and provide a reasonable initial estimate of the amount of released product. (d) New information. Within 48 hours after the confirmed discovery of an accident, to the extent practicable, an operator must revise or confirm its initial telephonic notice required in paragraph (b) of this section with a revised estimate of the amount of product released, location of the failure, time of the failure, a revised estimate of the number of fatalities and injuries, and all other significant facts that are known by the operator that are relevant to the cause of the accident or extent of the damages. If there are no changes or revisions to the initial report, the operator must confirm the estimates in its initial report." 49:49:3.1.1.2.11.2.20.5,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,B,"Subpart B—Annual, Accident, and Safety-Related Condition Reporting",,§ 195.54 Accident reports.,PHMSA,,,"[Amdt. 195-39, 53 FR 24950, July 1, 1988, as amended by Amdt. 195-95, 75 FR 72907, Nov. 26, 2010; Amdt. 195-117, 90 FR 40766, Aug. 21, 2025]","(a) Each operator that experiences an accident that is required to be reported under § 195.50 must, as soon as practicable, but not later than 30 days after discovery of the accident, file an accident report on DOT Form 7000-1 or 7000-2, whichever is applicable. (b) Whenever an operator receives any changes in the information reported or additions to the original report on DOT Form 7000-1 or 7000-2, whichever is applicable, it shall file a supplemental report within 30 days." 49:49:3.1.1.2.11.2.20.6,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,B,"Subpart B—Annual, Accident, and Safety-Related Condition Reporting",,§ 195.55 Reporting safety-related conditions.,PHMSA,,,"[Amdt. 195-39, 53 FR 24950, July 1, 1988; 53 FR 29800, Aug. 8, 1988, as amended by Amdt. 195-63, 63 FR 37506, July 13, 1998]","(a) Except as provided in paragraph (b) of this section, each operator shall report in accordance with § 195.56 the existence of any of the following safety-related conditions involving pipelines in service: (1) General corrosion that has reduced the wall thickness to less than that required for the maximum operating pressure, and localized corrosion pitting to a degree where leakage might result. (2) Unintended movement or abnormal loading of a pipeline by environmental causes, such as an earthquake, landslide, or flood, that impairs its serviceability. (3) Any material defect or physical damage that impairs the serviceability of a pipeline. (4) Any malfunction or operating error that causes the pressure of a pipeline to rise above 110 percent of its maximum operating pressure. (5) A leak in a pipeline that constitutes an emergency. (6) Any safety-related condition that could lead to an imminent hazard and causes (either directly or indirectly by remedial action of the operator), for purposes other than abandonment, a 20 percent or more reduction in operating pressure or shutdown of operation of a pipeline. (b) A report is not required for any safety-related condition that— (1) Exists on a pipeline that is more than 220 yards (200 meters) from any building intended for human occupancy or outdoor place of assembly, except that reports are required for conditions within the right-of-way of an active railroad, paved road, street, or highway, or that occur offshore or at onshore locations where a loss of hazardous liquid could reasonably be expected to pollute any stream, river, lake, reservoir, or other body of water; (2) Is an accident that is required to be reported under § 195.50 or results in such an accident before the deadline for filing the safety-related condition report; or (3) Is corrected by repair or replacement in accordance with applicable safety standards before the deadline for filing the safety-related condition report, except that reports are required for all conditions under paragraph (a)(1) of this section other than localized corrosion pitting on an effectively coated and cathodically protected pipeline." 49:49:3.1.1.2.11.2.20.7,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,B,"Subpart B—Annual, Accident, and Safety-Related Condition Reporting",,§ 195.56 Filing safety-related condition reports.,PHMSA,,,"[Amdt. 195-39, 53 FR 24950, July 1, 1988; 53 FR 29800, Aug. 8, 1988, as amended by Amdt. 195-42, 54 FR 32344, Aug. 7, 1989; Amdt. 195-44, 54 FR 40878, Oct. 4, 1989; Amdt. 195-50, 59 FR 17281, Apr. 12, 1994; Amdt. 195-61, 63 FR 7723, Feb. 17, 1998; Amdt. 195-100, 80 FR 12780, Mar. 11, 2015]","(a) Each report of a safety-related condition under § 195.55(a) must be filed (received by OPS) within five working days (not including Saturday, Sunday, or Federal Holidays) after the day a representative of the operator first determines that the condition exists, but not later than 10 working days after the day a representative of the operator discovers the condition. Separate conditions may be described in a single report if they are closely related. Reports may be transmitted by electronic mail to InformationResourcesManager@dot.gov, or by facsimile at (202) 366-7128. (b) The report must be headed “Safety-Related Condition Report” and provide the following information: (1) Name and principal address of operator. (2) Date of report. (3) Name, job title, and business telephone number of person submitting the report. (4) Name, job title, and business telephone number of person who determined that the condition exists. (5) Date condition was discovered and date condition was first determined to exist. (6) Location of condition, with reference to the State (and town, city, or county) or offshore site, and as appropriate nearest street address, offshore platform, survey station number, milepost, landmark, or name of pipeline. (7) Description of the condition, including circumstances leading to its discovery, any significant effects of the condition on safety, and the name of the commodity transported or stored. (8) The corrective action taken (including reduction of pressure or shutdown) before the report is submitted and the planned follow-up or future corrective action, including the anticipated schedule for starting and concluding such action." 49:49:3.1.1.2.11.2.20.8,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,B,"Subpart B—Annual, Accident, and Safety-Related Condition Reporting",,§ 195.58 Report submission requirements.,PHMSA,,,"[Amdt. 195-95, 75 FR 72907, Nov. 26, 2010, as amended by Amdt. 195-100, 80 FR 12780, Mar. 11, 2015; Amdts. 192-135, 195-107, 89 FR 33284, Apr. 29, 2024]","(a) General. Except as provided in paragraphs (b) and (e) of this section, an operator must submit each report required by this part electronically to PHMSA at https://portal.phmsa.dot.gov unless an alternative reporting method is authorized in accordance with paragraph (d) of this section. (b) Exceptions: An operator is not required to submit a safety-related condition report (§ 195.56) electronically. (c) Safety-related conditions. An operator must submit concurrently to the applicable State agency a safety-related condition report required by § 195.55 for an intrastate pipeline or when the State agency acts as an agent of the Secretary with respect to interstate pipelines. (d) Alternate Reporting Method. If electronic reporting imposes an undue burden and hardship, the operator may submit a written request for an alternative reporting method to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, PHP-20, 1200 New Jersey Avenue, SE., Washington DC 20590. The request must describe the undue burden and hardship. PHMSA will review the request and may authorize, in writing, an alternative reporting method. An authorization will state the period for which it is valid, which may be indefinite. An operator must contact PHMSA at 202-366-8075, or electronically to “ informationresourcesmanager@dot.gov” to make arrangements for submitting a report that is due after a request for alternative reporting is submitted but before an authorization or denial is received. (e) National Pipeline Mapping System (NPMS). An operator must provide NPMS data to the address identified in the NPMS Operator Standards Manual available at www.npms.phmsa.dot.gov or by contacting the PHMSA Geographic Information Systems Manager at (202) 366-4595." 49:49:3.1.1.2.11.2.20.9,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,B,"Subpart B—Annual, Accident, and Safety-Related Condition Reporting",,§ 195.59 Abandonment or deactivation of facilities.,PHMSA,,,"[Amdt. 195-69, 65 FR 54444, Sept. 8, 2000, as amended at 70 FR 11140, Mar. 8, 2005; Amdt. 195-86, 72 FR 4657, Feb. 1, 2007; 73 FR 16570, Mar. 28, 2008; 74 FR 2894, Jan. 16, 2009; Amdts. 192-135, 195-107, 89 FR 33284, Apr. 29, 2024]","For each abandoned offshore pipeline facility or each abandoned onshore pipeline facility that crosses over, under or through a commercially navigable waterway, the last operator of that facility must file a report upon abandonment of that facility. (a) The preferred method to submit data on pipeline facilities abandoned after October 10, 2000, is to the National Pipeline Mapping System (NPMS) in accordance with the NPMS “Standards for Pipeline and Liquefied Natural Gas Operator Submissions.” To obtain a copy of the NPMS standards, please refer to the NPMS homepage at https://www.npms.phmsa.dot.gov. A digital data format is preferred, but hard copy submissions are acceptable if they comply with the NPMS Standards. In addition to the NPMS-required attributes, operators must submit the date of abandonment, diameter, method of abandonment, and certification that, to the best of the operator's knowledge, all of the reasonably available information requested was provided and, to the best of the operator's knowledge, the abandonment was completed in accordance with applicable laws. Refer to the NPMS Standards for details in preparing your data for submission. The NPMS Standards also include details of how to submit data. Alternatively, operators may submit reports by mail, fax or email to the Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, Information Resources Manager, PHP-10, 1200 New Jersey Avenue SE, Washington, DC 20590-0001; fax: (202) 366-4566; email: InformationResourcesManager@dot.gov. The information in the report must contain all reasonably available information related to the facility, including information in the possession of a third party. The report must contain the location, size, date, method of abandonment, and a certification that the facility has been abandoned in accordance with all applicable laws. (b) [Reserved]" 49:49:3.1.1.2.11.3.20.1,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.100 Scope.,PHMSA,,,,"This subpart prescribes minimum design requirements for new pipeline systems constructed with steel pipe and for relocating, replacing, or otherwise changing existing systems constructed with steel pipe. However, it does not apply to the movement of line pipe covered by § 195.424." 49:49:3.1.1.2.11.3.20.10,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.114 Used pipe.,PHMSA,,,"[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982]","Any used pipe installed in a pipeline system must comply with § 195.112 (a) and (b) and the following: (a) The pipe must be of a known specification and the seam joint factor must be determined in accordance with § 195.106(e). If the specified minimum yield strength or the wall thickness is not known, it is determined in accordance with § 195.106 (b) or (c) as appropriate. (b) There may not be any: (1) Buckles; (2) Cracks, grooves, gouges, dents, or other surface defects that exceed the maximum depth of such a defect permitted by the specification to which the pipe was manufactured; or (3) Corroded areas where the remaining wall thickness is less than the minimum thickness required by the tolerances in the specification to which the pipe was manufactured. However, pipe that does not meet the requirements of paragraph (b)(3) of this section may be used if the operating pressure is reduced to be commensurate with the remaining wall thickness." 49:49:3.1.1.2.11.3.20.11,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.116 Valves.,PHMSA,,,"[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-45, 56 FR 26926, June 12, 1991; Amdt. 195-86, 71 FR 33410, June 9, 2006; Amdt. 195-94, 75 FR 48606, Aug. 11, 2010; Amdt. 195-99, 80 FR 186, Jan. 5, 2015; Amdts. 192-135, 195-107, 89 FR 33284, Apr. 29, 2024]","Each valve installed in a pipeline system must comply with the following: (a) The valve must be of a sound engineering design. (b) Materials subject to the internal pressure of the pipeline system, including welded and flanged ends, must be compatible with the pipe or fittings to which the valve is attached. (c) Each part of the valve that will be in contact with the carbon dioxide or hazardous liquid stream must be made of materials that are compatible with carbon dioxide or each hazardous liquid that it is anticipated will flow through the pipeline system. (d) Each valve must be both hydrostatically shell tested and hydrostatically seat tested without leakage to at least the requirements set forth in Section 11 of API Spec 6D (incorporated by reference, see § 195.3). (e) Each valve other than a check valve must be equipped with a means for clearly indicating the position of the valve (open, closed, etc.). (f) Each valve must be marked on the body or the nameplate, with at least the following: (1) Manufacturer's name or trademark. (2) Class designation or the maximum working pressure to which the valve may be subjected. (3) Body material designation (the end connection material, if more than one type is used). (4) Nominal valve size." 49:49:3.1.1.2.11.3.20.12,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.118 Fittings.,PHMSA,,,"[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, as amended at 58 FR 14524, Mar. 18, 1993; Amdt. 195-99, 80 FR 186, Jan. 5, 2015]","(a) Butt-welding type fittings must meet the marking, end preparation, and the bursting strength requirements of ASME/ANSI B16.9 or MSS SP-75 (incorporated by reference, see § 195.3). (b) There may not be any buckles, dents, cracks, gouges, or other defects in the fitting that might reduce the strength of the fitting. (c) The fitting must be suitable for the intended service and be at least as strong as the pipe and other fittings in the pipeline system to which it is attached." 49:49:3.1.1.2.11.3.20.13,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.120 Passage of internal inspection devices.,PHMSA,,,"[Amdt. 195-102, 84 FR 52294, Oct. 1, 2019]","(a) General. Except as provided in paragraphs (b) and (c) of this section, each new pipeline and each main line section of a pipeline where the line pipe, valve, fitting or other line component is replaced must be designed and constructed to accommodate the passage of instrumented internal inspection devices in accordance with NACE SP0102 (incorporated by reference, see § 195.3). (b) Exceptions. This section does not apply to: (1) Manifolds; (2) Station piping such as at pump stations, meter stations, or pressure reducing stations; (3) Piping associated with tank farms and other storage facilities; (4) Cross-overs; (5) Pipe for which an instrumented internal inspection device is not commercially available; and (6) Offshore pipelines, other than lines 10 inches (254 millimeters) or greater in nominal diameter, that transport liquids to onshore facilities. (c) Impracticability. An operator may file a petition under § 190.9 for a finding that the requirements in paragraph (a) of this section should not be applied to a pipeline for reasons of impracticability. (d) Emergencies. An operator need not comply with paragraph (a) of this section in constructing a new or replacement segment of a pipeline in an emergency. Within 30 days after discovering the emergency, the operator must file a petition under § 190.9 for a finding that requiring the design and construction of the new or replacement pipeline segment to accommodate passage of instrumented internal inspection devices would be impracticable as a result of the emergency. If PHMSA denies the petition, within 1 year after the date of the notice of the denial, the operator must modify the new or replacement pipeline segment to allow passage of instrumented internal inspection devices." 49:49:3.1.1.2.11.3.20.14,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.122 Fabricated branch connections.,PHMSA,,,,Each pipeline system must be designed so that the addition of any fabricated branch connections will not reduce the strength of the pipeline system. 49:49:3.1.1.2.11.3.20.15,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.124 Closures.,PHMSA,,,"[Amdt. 195-99, 80 FR 186, Jan. 5, 2015]","Each closure to be installed in a pipeline system must comply with the 2007 ASME Boiler and Pressure Vessel Code (BPVC) (Section VIII, Division 1) (incorporated by reference, see § 195.3) and must have pressure and temperature ratings at least equal to those of the pipe to which the closure is attached." 49:49:3.1.1.2.11.3.20.16,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.126 Flange connection.,PHMSA,,,,Each component of a flange connection must be compatible with each other component and the connection as a unit must be suitable for the service in which it is to be used. 49:49:3.1.1.2.11.3.20.17,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.128 Station piping.,PHMSA,,,,Any pipe to be installed in a station that is subject to system pressure must meet the applicable requirements of this subpart. 49:49:3.1.1.2.11.3.20.18,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.130 Fabricated assemblies.,PHMSA,,,,Each fabricated assembly to be installed in a pipeline system must meet the applicable requirements of this subpart. 49:49:3.1.1.2.11.3.20.19,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.132 Design and construction of aboveground breakout tanks.,PHMSA,,,"[Amdt. 195-66, 64 FR 15935, Apr. 2, 1999, as amended by Amdt. 195-99, 80 FR 186, Jan. 5, 2015; 80 FR 46848, Aug. 6, 2015]","(a) Each aboveground breakout tank must be designed and constructed to withstand the internal pressure produced by the hazardous liquid to be stored therein and any anticipated external loads. (b) For aboveground breakout tanks first placed in service after October 2, 2000, compliance with paragraph (a) of this section requires one of the following: (1) Shop-fabricated, vertical, cylindrical, closed top, welded steel tanks with nominal capacities of 90 to 750 barrels (14.3 to 119.2 m 3 ) and with internal vapor space pressures that are approximately atmospheric must be designed and constructed in accordance with API Spec 12F (incorporated by reference, see § 195.3) . (2) Welded, low-pressure ( i.e. , internal vapor space pressure not greater than 15 psig (103.4 kPa)), carbon steel tanks that have wall shapes that can be generated by a single vertical axis of revolution must be designed and constructed in accordance with API Std 620 (incorporated by reference, see § 195.3). (3) Vertical, cylindrical, welded steel tanks with internal pressures at the tank top approximating atmospheric pressures ( i.e. , internal vapor space pressures not greater than 2.5 psig (17.2 kPa), or not greater than the pressure developed by the weight of the tank roof) must be designed and constructed in accordance with API Std 650 (incorporated by reference, see § 195.3). (4) High pressure steel tanks ( i.e. , internal gas or vapor space pressures greater than 15 psig (103.4 kPa)) with a nominal capacity of 2000 gallons (7571 liters) or more of liquefied petroleum gas (LPG) must be designed and constructed in accordance with API Std 2510 (incorporated by reference, see § 195.3)." 49:49:3.1.1.2.11.3.20.2,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.101 Qualifying metallic components other than pipe.,PHMSA,,,"[Amdt. 195-28, 48 FR 30639, July 5, 1983]","Notwithstanding any requirement of the subpart which incorporates by reference an edition of a document listed in § 195.3, a metallic component other than pipe manufactured in accordance with any other edition of that document is qualified for use if— (a) It can be shown through visual inspection of the cleaned component that no defect exists which might impair the strength or tightness of the component: and (b) The edition of the document under which the component was manufactured has equal or more stringent requirements for the following as an edition of that document currently or previously listed in § 195.3: (1) Pressure testing; (2) Materials; and (3) Pressure and temperature ratings." 49:49:3.1.1.2.11.3.20.20,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.134 Leak detection.,PHMSA,,,"[Amdt. 195-102, 84 FR 52295, Oct. 1, 2019]","(a) Scope. This section applies to each hazardous liquid pipeline transporting liquid in single phase (without gas in the liquid). (b) General. (1) For each pipeline constructed prior to October 1, 2019. Each pipeline must have a system for detecting leaks that complies with the requirements in § 195.444 by October 1, 2024. (2) For each pipeline constructed on or after October 1, 2019. Each pipeline must have a system for detecting leaks that complies with the requirements in § 195.444 by October 1, 2020. (c) CPM leak detection systems. A new computational pipeline monitoring (CPM) leak detection system or replaced component of an existing CPM system must be designed in accordance with the requirements in section 4.2 of API RP 1130 (incorporated by reference, see § 195.3) and any other applicable design criteria in that standard. (d) Exception. The requirements of paragraph (b) of this section do not apply to offshore gathering or regulated rural gathering lines." 49:49:3.1.1.2.11.3.20.3,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.102 Design temperature.,PHMSA,,,"[Amdt. 195-45, 56 FR 26925, June 12, 1991]","(a) Material for components of the system must be chosen for the temperature environment in which the components will be used so that the pipeline will maintain its structural integrity. (b) Components of carbon dioxide pipelines that are subject to low temperatures during normal operation because of rapid pressure reduction or during the initial fill of the line must be made of materials that are suitable for those low temperatures." 49:49:3.1.1.2.11.3.20.4,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.104 Variations in pressure.,PHMSA,,,,"If, within a pipeline system, two or more components are to be connected at a place where one will operate at a higher pressure than another, the system must be designed so that any component operating at the lower pressure will not be overstressed." 49:49:3.1.1.2.11.3.20.5,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.106 Internal design pressure.,PHMSA,,,"[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, as amended by Amdt. 195-30, 49 FR 7569, Mar. 1, 1984; Amdt. 195-37, 51 FR 15335, Apr. 23, 1986; Amdt. 195-40, 54 FR 5628, Feb. 6, 1989; 58 FR 14524, Mar. 18, 1993; Amdt. 195-50, 59 FR 17281, Apr. 12, 1994; Amdt. 195-52, 59 FR 33396, 33397, June 28, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998; Amdt. 195-99, 80 FR 185, Jan. 5, 2015; Amdts. 192-135, 195-107, 89 FR 33284, Apr. 29, 2024]","(a) Internal design pressure for the pipe in a pipeline is determined in accordance with the following formula: P = (2 St/D ) × E × F P = Internal design pressure in p.s.i. (kPa) gage. S = Yield strength in pounds per square inch (kPa) determined in accordance with paragraph (b) of this section. t = Nominal wall thickness of the pipe in inches (millimeters). If this is unknown, it is determined in accordance with paragraph (c) of this section. D = Nominal outside diameter of the pipe in inches (millimeters). E = Seam joint factor determined in accordance with paragraph (e) of this section. F = A design factor of 0.72, except that a design factor of 0.60 is used for pipe, including risers, on a platform located offshore or on a platform in inland navigable waters, and 0.54 is used for pipe that has been subjected to cold expansion to meet the specified minimum yield strength and is subsequently heated, other than by welding or stress relieving as a part of welding, to a temperature higher than 900 °F (482 °C) for any period of time or over 600 °F (316 °C) for more than 1 hour. P = Internal design pressure in p.s.i. (kPa) gage. S = Yield strength in pounds per square inch (kPa) determined in accordance with paragraph (b) of this section. t = Nominal wall thickness of the pipe in inches (millimeters). If this is unknown, it is determined in accordance with paragraph (c) of this section. D = Nominal outside diameter of the pipe in inches (millimeters). E = Seam joint factor determined in accordance with paragraph (e) of this section. F = A design factor of 0.72, except that a design factor of 0.60 is used for pipe, including risers, on a platform located offshore or on a platform in inland navigable waters, and 0.54 is used for pipe that has been subjected to cold expansion to meet the specified minimum yield strength and is subsequently heated, other than by welding or stress relieving as a part of welding, to a temperature higher than 900 °F (482 °C) for any period of time or over 600 °F (316 °C) for more than 1 hour. (b) The yield strength to be used in determining the internal design pressure under paragraph (a) of this section is the specified minimum yield strength. If the specified minimum yield strength is not known, the yield strength to be used in the design formula is one of the following: (1)(i) The yield strength determined by performing all of the tensile tests of API Spec 5L (incorporated by reference, see § 195.3) on randomly selected specimens with the following number of tests: (ii) If the average yield-tensile ratio exceeds 0.85, the yield strength shall be taken as 24,000 p.s.i. (165,474 kPa). If the average yield-tensile ratio is 0.85 or less, the yield strength of the pipe is taken as the lower of the following: (A) Eighty percent of the average yield strength determined by the tensile tests. (B) The lowest yield strength determined by the tensile tests. (2) If the pipe is not tensile tested as provided in paragraph (b) of this section, the yield strength shall be taken as 24,000 p.s.i. (165,474 kPa). (c) If the nominal wall thickness to be used in determining internal design pressure under paragraph (a) of this section is not known, it is determined by measuring the thickness of each piece of pipe at quarter points on one end. However, if the pipe is of uniform grade, size, and thickness, only 10 individual lengths or 5 percent of all lengths, whichever is greater, need be measured. The thickness of the lengths that are not measured must be verified by applying a gage set to the minimum thickness found by the measurement. The nominal wall thickness to be used is the next wall thickness found in commercial specifications that is below the average of all the measurements taken. However, the nominal wall thickness may not be more than 1.14 times the smallest measurement taken on pipe that is less than 20 inches (508 mm) nominal outside diameter, nor more than 1.11 times the smallest measurement taken on pipe that is 20 inches (508 mm) or more in nominal outside diameter. (d) The minimum wall thickness of the pipe may not be less than 87.5 percent of the value used for nominal wall thickness in determining the internal design pressure under paragraph (a) of this section. In addition, the anticipated external loads and external pressures that are concurrent with internal pressure must be considered in accordance with §§ 195.108 and 195.110 and, after determining the internal design pressure, the nominal wall thickness must be increased as necessary to compensate for these concurrent loads and pressures. (e)(1) The seam joint factor used in paragraph (a) of this section is determined in accordance with the following standards incorporated by reference ( see § 195.3): (2) The seam joint factor for pipe that is not covered by this paragraph must be approved by the Administrator." 49:49:3.1.1.2.11.3.20.6,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.108 External pressure.,PHMSA,,,,Any external pressure that will be exerted on the pipe must be provided for in designing a pipeline system. 49:49:3.1.1.2.11.3.20.7,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.110 External loads.,PHMSA,,,"[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended at 58 FR 14524, Mar. 18, 1993; Amdts. 192-135, 195-107, 89 FR 33284, Apr. 29, 2024; Amdt. 195-117, 90 FR 40766, Aug. 21, 2025]","(a) Anticipated external loads ( e.g., earthquakes, vibration, thermal expansion, and contraction) must be provided for in a pipeline system's design. Sections 401, 402, 403.3, and 403.9 of ASME B31.4 (incorporated by reference, see § 195.3) must be followed to provide for expansion and flexibility. (b) The pipe and other components must be supported in such a way that the support does not cause excess localized stresses. In designing attachments to pipe, the added stress to the wall of the pipe must be computed and compensated for." 49:49:3.1.1.2.11.3.20.8,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.111 Fracture propagation.,PHMSA,,,"[Amdt. 195-45, 56 FR 26926, June 12, 1991]",A carbon dioxide pipeline system must be designed to mitigate the effects of fracture propagation. 49:49:3.1.1.2.11.3.20.9,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,C,Subpart C—Design Requirements,,§ 195.112 New pipe.,PHMSA,,,"[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 59 FR 33396, June 28, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998]","Any new pipe installed in a pipeline system must comply with the following: (a) The pipe must be made of steel of the carbon, low alloy-high strength, or alloy type that is able to withstand the internal pressures and external loads and pressures anticipated for the pipeline system. (b) The pipe must be made in accordance with a written pipe specification that sets forth the chemical requirements for the pipe steel and mechanical tests for the pipe to provide pipe suitable for the use intended. (c) Each length of pipe with a nominal outside diameter of 4 1/2 in (114.3 mm) or more must be marked on the pipe or pipe coating with the specification to which it was made, the specified minimum yield strength or grade, and the pipe size. The marking must be applied in a manner that does not damage the pipe or pipe coating and must remain visible until the pipe is installed." 49:49:3.1.1.2.11.4.20.1,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,D,Subpart D—Construction,,§ 195.200 Scope.,PHMSA,,,,"This subpart prescribes minimum requirements for constructing new pipeline systems with steel pipe, and for relocating, replacing, or otherwise changing existing pipeline systems that are constructed with steel pipe. However, this subpart does not apply to the movement of pipe covered by § 195.424." 49:49:3.1.1.2.11.4.20.10,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,D,Subpart D—Construction,,§ 195.214 Welding procedures.,PHMSA,,,"[Amdt. 195-38, 51 FR 20297, June 4, 1986, as amended at Amdt. 195-81, 69 FR 32897, June 14, 2004; Amdt. 195-99, 80 FR 186, Jan. 5, 2015; Amdt. 195-100, 80 FR 12780, Mar. 11, 2015; Amdt. 195-101, 82 FR 7999, Jan. 23, 2017; Amdts. 192-135, 195-107, 89 FR 33284, Apr. 29, 2024]","(a) Welding must be performed by a qualified welder or welding operator in accordance with welding procedures qualified under section 5 (except for Note 2 in section 5.4.2.2), section 12, Appendix A or Appendix B of API Std 1104 (incorporated by reference, see § 195.3), or Section IX of the ASME Boiler and Pressure Vessel Code (ASME BPVC) (incorporated by reference, see § 195.3). The quality of the test welds used to qualify the welding procedures must be determined by destructive testing. (b) Each welding procedure must be recorded in detail, including the results of the qualifying tests. This record must be retained and followed whenever the procedure is used." 49:49:3.1.1.2.11.4.20.11,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,D,Subpart D—Construction,,§ 195.216 Welding: Miter joints.,PHMSA,,,,A miter joint is not permitted (not including deflections up to 3 degrees that are caused by misalignment). 49:49:3.1.1.2.11.4.20.12,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,D,Subpart D—Construction,,§ 195.222 Welders and welding operators: Qualification of welders and welding operators.,PHMSA,,,"[Amdt. 195-81, 69 FR 54593, Sept. 9, 2004, as amended by Amdt. 195-86, 71 FR 33409, June 9, 2006; Amdt. 195-99, 80 FR 186, Jan. 5, 2015; Amdt. 195-100, 80 FR 12780, Mar. 11, 2015; Amdt. 195-101, 82 FR 7999, Jan. 23, 2017]","(a) Each welder or welding operator must be qualified in accordance with section 6, section 12, Appendix A or Appendix B of API Std 1104 (incorporated by reference, see § 195.3), or section IX of the ASME Boiler and Pressure Vessel Code (ASME BPVC), (incorporated by reference, see § 195.3) except that a welder or welding operator qualified under an earlier edition than listed in § 195.3, may weld but may not requalify under that earlier edition. (b) No welder or welding operator may weld with a welding process unless, within the preceding 6 calendar months, the welder or welding operator has— (1) Engaged in welding with that process; and (2) Had one weld tested and found acceptable under section 9 or Appendix A of API Std 1104 (incorporated by reference, see § 195.3)." 49:49:3.1.1.2.11.4.20.13,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,D,Subpart D—Construction,,§ 195.224 Welding: Weather.,PHMSA,,,,Welding must be protected from weather conditions that would impair the quality of the completed weld. 49:49:3.1.1.2.11.4.20.14,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,D,Subpart D—Construction,,§ 195.226 Welding: Arc burns.,PHMSA,,,,"(a) Each arc burn must be repaired. (b) An arc burn may be repaired by completely removing the notch by grinding, if the grinding does not reduce the remaining wall thickness to less than the minimum thickness required by the tolerances in the specification to which the pipe is manufactured. If a notch is not repairable by grinding, a cylinder of the pipe containing the entire notch must be removed. (c) A ground may not be welded to the pipe or fitting that is being welded." 49:49:3.1.1.2.11.4.20.15,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,D,Subpart D—Construction,,§ 195.228 Welds and welding inspection: Standards of acceptability.,PHMSA,,,"[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 59 FR 33397, June 28, 1994; Amdt. 195-81, 69 FR 32898, June 14, 2004; Amdt. 195-99, 80 FR 186, Jan. 5, 2015; Amdt. 195-100, 80 FR 12780, Mar. 11, 2015]","(a) Each weld and welding must be inspected to insure compliance with the requirements of this subpart. Visual inspection must be supplemented by nondestructive testing. (b) The acceptability of a weld is determined according to the standards in section 9 or Appendix A of API Std 1104 (incorporated by reference, see § 195.3). Appendix A of API Std 1104 may not be used to accept cracks." 49:49:3.1.1.2.11.4.20.16,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,D,Subpart D—Construction,,§ 195.230 Welds: Repair or removal of defects.,PHMSA,,,"[Amdt. 195-29, 48 FR 48674, Oct. 20, 1983]","(a) Each weld that is unacceptable under § 195.228 must be removed or repaired. Except for welds on an offshore pipeline being installed from a pipelay vessel, a weld must be removed if it has a crack that is more than 8 percent of the weld length. (b) Each weld that is repaired must have the defect removed down to sound metal and the segment to be repaired must be preheated if conditions exist which would adversely affect the quality of the weld repair. After repair, the segment of the weld that was repaired must be inspected to ensure its acceptability. (c) Repair of a crack, or of any defect in a previously repaired area must be in accordance with written weld repair procedures that have been qualified under § 195.214. Repair procedures must provide that the minimum mechanical properties specified for the welding procedure used to make the original weld are met upon completion of the final weld repair." 49:49:3.1.1.2.11.4.20.17,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,D,Subpart D—Construction,,§ 195.234 Welds: Nondestructive testing.,PHMSA,,,"[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-35, 50 FR 37192, Sept. 21, 1985; Amdt. 195-52, 59 FR 33397, June 28, 1994; Amdt. 195-100, 80 FR 12780, Mar. 11, 2015]","(a) A weld may be nondestructively tested by any process that will clearly indicate any defects that may affect the integrity of the weld. (b) Any nondestructive testing of welds must be performed— (1) In accordance with a written set of procedures for nondestructive testing; and (2) With personnel that have been trained in the established procedures and in the use of the equipment employed in the testing. (c) Procedures for the proper interpretation of each weld inspection must be established to ensure the acceptability of the weld under § 195.228. (d) During construction, at least 10 percent of the girth welds made by each welder and welding operator during each welding day must be nondestructively tested over the entire circumference of the weld. (e) All girth welds installed each day in the following locations must be nondestructively tested over their entire circumference, except that when nondestructive testing is impracticable for a girth weld, it need not be tested if the number of girth welds for which testing is impracticable does not exceed 10 percent of the girth welds installed that day: (1) At any onshore location where a loss of hazardous liquid could reasonably be expected to pollute any stream, river, lake, reservoir, or other body of water, and any offshore area; (2) Within railroad or public road rights-of-way; (3) At overhead road crossings and within tunnels; (4) Within the limits of any incorporated subdivision of a State government; and (5) Within populated areas, including, but not limited to, residential subdivisions, shopping centers, schools, designated commercial areas, industrial facilities, public institutions, and places of public assembly. (f) When installing used pipe, 100 percent of the old girth welds must be nondestructively tested. (g) At pipeline tie-ins, including tie-ins of replacement sections, 100 percent of the girth welds must be nondestructively tested." 49:49:3.1.1.2.11.4.20.18,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,D,Subpart D—Construction,,§§ 195.236-195.244 [Reserved],PHMSA,,,, 49:49:3.1.1.2.11.4.20.19,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,D,Subpart D—Construction,,§ 195.246 Installation of pipe in a ditch.,PHMSA,,,"[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 59 FR 33397, June 28, 1994; 59 FR 36256, July 15, 1994; Amdt. 195-85, 69 FR 48407, Aug. 10, 2004; Amdt. 195-108, 90 FR 21436, May 20, 2025]","(a) All pipe installed in a ditch must be installed in a manner that minimizes the introduction of secondary stresses and the possibility of damage to the pipe. (b) Except for pipe in the Gulf of America and its inlets in waters less than 15 feet deep, all offshore pipe in water at least 12 feet deep (3.7 meters) but not more than 200 feet deep (61 meters) deep as measured from the mean low water must be installed so that the top of the pipe is below the underwater natural bottom (as determined by recognized and generally accepted practices) unless the pipe is supported by stanchions held in place by anchors or heavy concrete coating or protected by an equivalent means." 49:49:3.1.1.2.11.4.20.2,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,D,Subpart D—Construction,,§ 195.202 Compliance with specifications or standards.,PHMSA,,,,Each pipeline system must be constructed in accordance with comprehensive written specifications or standards that are consistent with the requirements of this part. 49:49:3.1.1.2.11.4.20.20,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,D,Subpart D—Construction,,§ 195.248 Cover over buried pipeline.,PHMSA,,,"[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, as amended by Amdt. 195-52, 59 FR 33397, June 28, 1994; 59 FR 36256, July 15, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998; Amdt. 195-95, 69 FR 48407, Aug. 10, 2004; Amdt. 195-101, 82 FR 7999, Jan. 23, 2017; Amdt. 195-108, 90 FR 21436, May 20, 2025]","(a) Unless specifically exempted in this subpart, all pipe must be buried so that it is below the level of cultivation. Except as provided in paragraph (b) of this section, the pipe must be installed so that the cover between the top of the pipe and the ground level, road bed, river bottom, or underwater natural bottom (as determined by recognized and generally accepted practices), as applicable, complies with the following table: 1 Rock excavation is any excavation that requires blasting or removal by equivalent means. (b) Except for the Gulf of America and its inlets in waters less than 15 feet (4.6 meters) deep, less cover than the minimum required by paragraph (a) of this section and § 195.210 may be used if— (1) It is impracticable to comply with the minimum cover requirements; and (2) Additional protection is provided that is equivalent to the minimum required cover." 49:49:3.1.1.2.11.4.20.21,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,D,Subpart D—Construction,,§ 195.250 Clearance between pipe and underground structures.,PHMSA,,,"[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-63, 63 FR 37506, July 13, 1998]","Any pipe installed underground must have at least 12 inches (305 millimeters) of clearance between the outside of the pipe and the extremity of any other underground structure, except that for drainage tile the minimum clearance may be less than 12 inches (305 millimeters) but not less than 2 inches (51 millimeters). However, where 12 inches (305 millimeters) of clearance is impracticable, the clearance may be reduced if adequate provisions are made for corrosion control." 49:49:3.1.1.2.11.4.20.22,49,Transportation,I,D,195,PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE,D,Subpart D—Construction,,§ 195.252 Backfilling.,PHMSA,,,"[Amdt. 195-78, 68 FR 53528, Sept. 11, 2003]","When a ditch for a pipeline is backfilled, it must be backfilled in a manner that: (a) Provides firm support under the pipe; and (b) Prevents damage to the pipe and pipe coating from equipment or from the backfill material."