# DIMP Enforcement Guidance - **operation:** document - **citation:** PHMSA Guidance, DIMP Enforcement Guidance - **title:** DIMP Enforcement Guidance - **source type:** guidance - **agency:** Pipeline and Hazardous Materials Safety Administration - **status:** guidance - **official:** true - **published on:** 2015-12-07 - **effective on:** 2015-12-07 - **summary:** DIMP Enforcement Guidance Document DIMP_Enforcement_Guidance_12_7_2015.pdf (686.32 KB) Distribution Integrity Management Plan (DIMP) Enforcement Guidance. The materials contained in this document consist of guidance, techniques, procedures and other information for internal use by the PHMSA pipeline safety enforcement staff. This guidance document describes the practices used by PHMSA pipeline safety investigators an - **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-guidance-dimp-enforcement-guidance-a127db96.json - **markdown:** https://regulus.evalyn.ai/document/phmsa-guidance-dimp-enforcement-guidance-a127db96.md - **app url:** https://regulus.evalyn.ai/document/phmsa-guidance-dimp-enforcement-guidance-a127db96 - **source url:** https://www.phmsa.dot.gov/pipeline/enforcement/dimp-enforcement-guidance **body:** DIMP Enforcement Guidance Document DIMP_Enforcement_Guidance_12_7_2015.pdf (686.32 KB) Distribution Integrity Management Plan (DIMP) Enforcement Guidance. The materials contained in this document consist of guidance, techniques, procedures and other information for internal use by the PHMSA pipeline safety enforcement staff. This guidance document describes the practices used by PHMSA pipeline safety investigators and other enforcement personnel in undertaking their compliance, inspection, and enforcement activities. Issued Date: Monday, December 7, 2015 <<>> Gas Distribution Pipeline Integrity Management Enforcement Guidance 49 CFR Part 192 – Subpart P Introduction The materials contained in this document consist of guidance, techniques, procedures and other information for internal use by the PHMSA pipeline safety enforcement staff. This guidance document describes the practices used by PHMSA pipeline safety investigators and other enforcement personnel in undertaking their compliance, inspection, and enforcement activities. This document is U.S. Government property and is to be used in conjunction with official duties. The Federal pipeline safety regulations (49 CFR Parts 190-199) discussed in this guidance document contains legally binding requirements. This document is not a regulation and creates no new legal obligations. The regulation is controlling. The materials in this document are explanatory in nature and reflect PHMSA’s current application of the regulations in effect at the time of the issuance of the guidance. In preparing an enforcement action alleging a probable violation, an allegation must always be based on the failure to take a required action (or taking a prohibited action) that is set forth directly in the language of the regulation. An allegation should never be drafted in a manner that says the operator “violated the guidance.” Nothing in this guidance document is intended to diminish or otherwise affect the authority of PHMSA to carry out its statutory, regulatory or other official functions or to commit PHMSA to taking any action that is subject to its discretion. Nothing in this document is intended to and does not create any legal or equitable right or benefit, substantive or procedural, enforceable at law by any person or organization against PHMSA, its personnel, State agencies or officers carrying out programs authorized under Federal law. Decisions about specific investigations and enforcement cases are made according to the specific facts and circumstances at hand. Investigations and compliance determinations often require careful legal and technical analysis of complicated issues. Although this guidance document serves as a reference for the staff responsible for investigations and enforcement, no set of procedures or policies can replace the need for active and ongoing consultation with supervisors, colleagues, and the Office of Chief Counsel in enforcement matters. Comments and suggestions for future changes and additions to this guidance document are invited and should be forwarded to your supervisor. The materials in this guidance document may be modified or revoked without prior notice by PHMSA management. <<>> Table of Contents Glossary ........................................................................................................................................................................ 2 §192.1001 What definitions apply to this subpart? ....................................................................................................... 3 §192.1003 What do the regulations in this subpart cover? ............................................................................................ 5 §192.1005 What must a gas distribution operator (other than a master meter or small LPG operator) do to implement this part? ............................................................................................................................... 7 §192.1007 What are the required elements of an integrity management plan? 192.1007(a) Knowledge ..............................................................................................................................10 192.1007(b) Identify threat .........................................................................................................................15 192.1007(c) Evaluate and rank risk ...........................................................................................................21 192.1007(d) Identify and implement measures to address risks .................................................................26 192.1007 (e) Measure performance, monitor results, and evaluate effectiveness ......................................31 192.1007(f) Periodic Evaluation and Improvement ...................................................................................35 192.1007(g) Report results .........................................................................................................................38 §192.1009, §191.12 What must an operator report when a mechanical fitting fails? ................................................... 41 §192.1011 What records must an operator keep? ............................................................................................................. 43 §192.1013 When may an operator deviate from required periodic inspections under this part? .................................. 46 §192.1015 What must a master meter or small liquefied petroleum gas (LPG) operator do to implement this subpart? 192.1015(a) General ................................................................................................................................... 48 §192.1015(b) What are the required elements of an integrity management plan? 192.1015(b)(1) Knowledge ...........................................................................................................................51 192.1015(b)(2) Identify threats.....................................................................................................................55 192.1015(b)(3) Rank risks ............................................................................................................................60 192.1015(b)(4) Identify and implement measures to mitigate risks ..............................................................64 192.1015(b)(5) Measure performance, monitor results, and evaluate effectiveness.....................................68 192.1015(b)(6) Periodic Evaluation and Improvement ................................................................................70 §192.1015(c) What are the required elements of an integrity management plan? (c) Records ..................................... 73 Page 1 <<>> For a complete “Glossary of Terms” please refer to the following link: http://www.phmsa.dot.gov/staticfiles/PHMSA/Pipeline/TQGlossary/Glossary.html Page 2 <<>> Enforcement Guidance Revision Date Code Section Section Title Existing Code Language Origin of Code Last Amendment Interpretation Summaries Advisory Bulletin/Alert Notice Summaries Distribution Integrity Management Part 192 12/7/2015 §192.1001 What definitions apply to this subpart? The following definitions apply to this subpart: Excavation Damage means any impact that results in the need to repair or replace an underground facility due to a weakening, or the partial or complete destruction, of the facility, including, but not limited to, the protective coating, lateral support, cathodic protection or the housing for the line device or facility. Hazardous Leak means a leak that represents an existing or probable hazard to persons or property and requires immediate repair or continuous action until the conditions are no longer hazardous. Integrity Management Plan or IM Plan means a written explanation of the mechanisms or procedures the operator will use to implement its integrity management program and to ensure compliance with this subpart. Integrity Management Program or IM Program means an overall approach by an operator to ensure the integrity of its gas distribution system. Mechanical fitting means a mechanical device used to connect sections of pipe. The term “Mechanical fitting” applies only to: (1) Stab Type fittings; (2) Nut Follower Type fittings; (3) Bolted Type fittings; or (4) Other Compression Type fittings. Small LPG Operator means an operator of a liquefied petroleum gas (LPG) distribution pipeline that serves fewer than 100 customers from a single source. 192-113, 74 FR 63906, Dec. 4, 2009 192-116, 76 FR 5494, February 1, 2011 Page 3 <<>> Other Reference Material & Source Guidance Information 1. A line does not have to experience a leak or release to be considered to have been damaged by excavation damage. 2. An operator need not classify leaks as hazardous or non-hazardous provided it repairs all leaks when found. To qualify for this exclusion, an operator must treat all leaks as if they were hazardous, providing for immediate repair or continuous action until the leak is repaired. Examples of a Probable Violation or 1. Operator does not have a comprehensive list of definitions. 2. Operator does not include all definitions in their Distribution Integrity Management Plan (DIMP) or other plans. 3. Operator definitions are not consistent with Part 192. Inadequate Procedures Depending on the circumstances, some of the examples listed in this section may be inadequate plans and procedures, and not probable violations. Thus, the enforcement tool to address these issues would be a Notice of Amendment and not a Notice of Probable Violation or a Warning Letter. Section 3 of the Enforcement Procedures provides guidance on selecting the appropriate enforcement action. Examples of Evidence 1. Copy of written Distribution Integrity Management Plan (DIMP) or applicable portions that depict an omission or deficiency in the plan. 2. Operator records. Other Special Notations Page 4 <<>> Enforcement Guidance Revision Date Code Section Section Title Existing Code Language Origin of Code Last Amendment Interpretation Summaries Advisory Bulletin/Alert Notice Summaries Other Reference Material & Source Guidance Information Distribution Integrity Management Part 192 12/7/2015 §192.1003 What do the regulations in this subpart cover? General. This subpart prescribes minimum requirements for an IM program for any gas distribution pipeline covered under this part, including liquefied petroleum gas systems. A gas distribution operator, other than a master meter operator or a small LPG operator, must follow the requirements in Sec. §192.1005-192.1013 of this subpart. A master meter operator or small LPG operator of a gas distribution pipeline must follow the requirements in §192.1015 of this subpart. 192-113, 74 FR 63906, Dec. 4, 2009 Interpretation: PI-11-0016 Date: 09-12-2012 – Response to Atmos Energy; September 12, 2012 and DIMP FAQ C.3.7 asserting PHMSA’s position that farm taps have been historically considered service lines, a subset of distribution pipelines and are thus subject to all distribution line requirements. Interpretation: PI-11-0008 Date: 04-19-2011 - Response to Northern Natural Gas Company; Apr 19, 2011 and DIMP FAQ C.3.7 explained that - operators of distribution, gathering, and transmission lines whose system includes “farm taps” meeting the definition of a distribution line must have a DIMP covering these facilities. Distribution Integrity Management FAQs • C.2.1 Must peak shaving and LNG facilities connected to our distribution pipeline system be considered in our DIMP? 1. The DIMP must address all gas distribution systems covered by this part including systems in which the operator transports natural gas, liquefied petroleum gas (LPG), landfill gas (LFG), liquefied natural gas (LNG), and propane-air mixtures. 2. All distribution pipeline and appurtenances are subject to DIMP including mains, valves, fittings, regulator stations, drips, service lines, risers, service meter and regulator sets, farm taps, high pressure distribution systems and low pressure distribution systems. 3. Operators must follow their procedures. The DIMP and any individual procedures documents must include management approvals, origin date, and the effective date of the last revision. For additional information, see the guidance section of §192.1005. Page 5 <<>> Examples of a Probable Violation or Inadequate Procedures Examples of Evidence Other Special Notations 4. Master Meter and Small LPG operators are treated differently in the DIMP Rule than larger operators. For Master Meter and Small LPG operators, the integrity management program must include the appropriate set of mechanisms or procedures to develop and implement each program element. The operator may employ a written explanation of the process employed (mechanism) to develop and implement a required element that is less specific than a written procedure. The IM program for these pipelines should reflect the relative simplicity of these types of pipelines. The DIMP could be concise, but still must be sufficient for operator personnel to understand and implement the program on a consistent basis. 1. The operator’s DIMP does not include all of the operator’s distribution pipeline facilities. 2. The operator does not address LPG or other types of gas transported when applicable. 3. Necessary regulated pipeline systems are not covered by a DIMP. 4. The DIMP does not include all pipe and appurtenances. Depending on the circumstances, some of the examples listed in this section may be inadequate plans and procedures, and not probable violations. Thus, the enforcement tool to address these issues would be a Notice of Amendment and not a Notice of Probable Violation or a Warning Letter. Section 3 of the Enforcement Procedures provides guidance on selecting the appropriate enforcement action. 1. Copy of written DIMP or applicable portion that shows omission or deficiency in the DIMP. 2. Copies of the applicable pages of the DIMP showing that the operator has not clearly stated other types of gas are transported. 3. Operator records. 4. Documented photographic evidence demonstrating the violation. 5. Documented oral and/or written statements from operator personnel. Page 6 <<>> Enforcement Guidance Revision Date Code Section Section Title Existing Code Language Origin of Code Last Amendment Interpretation Summaries Advisory Bulletin/Alert Notice Summaries Other Reference Material & Source Distribution Integrity Management Part 192 12/7/2015 §192.1005 What must a gas distribution operator (other than a master meter or small LPG operator) do to implement this subpart? No later than August 2, 2011 a gas distribution operator must develop and implement an integrity management program that includes a written integrity management plan as specified in §192.1007. 192-113, 74 FR 63906, Dec. 4, 2009 Addressed in DIMP Final Rule preamble in Federal Register / Vol. 74, No. 232 / Friday, December 4, 2009 / Rules and Regulations at: • Comment Topic 4: Implementation time. Page 63909 • Comment Topic 11: Required documentation. Page 63915 Distribution Integrity Management FAQs • C.3.1 If an operator has both natural gas and LPG systems, must it have two separate DIMP plans or may it have a single plan? • C.3.2 Must an operator have one DIMP plan covering all of its systems or could it have separate plans for different systems or service areas? • C.3.3 Will companies operating in several states need to develop individual DIMP plans for each state? • C.3.4 What is the relationship between an operations & maintenance manual and a DIMP plan? • C.3.6 How does the new DIMP rule impact operators of gas piping systems on military bases, Federal Government, or Indian Tribal Government land? • C.3.7 Are operators required to include “farm taps” in their distribution integrity management plan? • C.3.8 What do operators need to have implemented by August 2, 2011? • C.3.10 What are the requirements for distribution systems put in service after 8/2/2011? • C.3.11 What are the requirements for distribution systems acquired after 8/2/2011? Page 7 <<>> Gas Piping Technology Committee (GPTC) Guide Material Appendix G-192-8 • Section 1 - Introduction 1.1-1.3 • Section 2 - Elements of a Distribution Integrity Management Plan 2.1-2.2 • Section 10 - Sample DIMP Approaches 10.1-10.2 Gas Distribution Integrity Management Program: Resources • DIMP Inspection Forms • Technical Reports • Distribution Integrity Management: Guidance for Master Meter and Small Liquefied Petroleum Gas Pipeline Operators • Plastic Piping Data Collection Initiative • Gas Piping Technology Committee (GPTC) Guide Material Appendix G-192-8 Distribution Management Integrity Program • SHRIMP - Simple Handy Rule based Integrity Management Plan • Industry Associations • Excavation Damage Prevention Organizations Guidance Information 1. From 192.1001: Integrity Management Plan or IM Plan “ means a written explanation of the mechanisms or procedures the operator will use to implement its integrity management program and to ensure compliance with this subpart.” An operator must have a written distribution integrity management plan (DIMP) that contains or references procedures for developing and implementing each required element in §192.1007. 2. The procedures must have adequate detail to clearly describe the manner in which each requirement will be met. 3. The procedure must be documented so an inspector can make a reasonable determination as to the accuracy and thoroughness of the procedure. The procedures need to provide a description of who, what, when, where, and how the operator will perform the elements. The DIMP can be concise, but still must be sufficient for operator personnel to understand and implement the program on a consistent basis. Operators must follow their procedures. 4. The DIMP and any individual procedures’ documents should include management approvals, origin date, and the effective date of the last revision. 5. From §192.1007, Integrity Management Program or IM Program “means an overall approach by an operator to ensure the integrity of its gas distribution system.” The operator’s integrity management program must include the appropriate set of procedures to develop and implement each program element as required in 192.1007. 6. An operator’s DIMP may vary in length and complexity depending on the specific equipment in service, the variety of facilities, the locations, and referenced versus incorporated material. 7. The structure of the DIMP is not prescribed and may consist of a single comprehensive DIMP or multiple cross-reference volumes with referenced documents. The DIMP can be made available to personnel as hard-copy or computer based documents but must be accessible at locations where DIMP required activities are conducted. If the DIMP is computer based, the operator must provide a means to access the procedures in the event of computer failure. Page 8 <<>> Examples of a Probable Violation or Inadequate Procedures Examples of Evidence Other Special Notations 8. Purchased or off-the-shelf plans and procedures must be fully customized to the operator to cover their specific operating requirements, and the procedures must have adequate detail to clearly describe the manner in which each requirement will be met. Guidance specific to an operator who transfers pipeline assets to another operator but retains responsibility, by contract, for maintenance and distribution integrity management activities. 1. Which operator is accountable for implementing the DIMP? OPS and the States inspect operators for compliance with the pipeline safety regulations. An ‘operator’ is defined in 49 C.F.R. §192.3 as “a person who engages in the transportation of gas”. A ‘person’ is further defined as an individual or firm, joint venture, partnership, corporation, association, State, municipality, cooperative association, or joint stock association, and including any trustee, receiver, assignee, or personal representative thereof. If an operator retains responsibility for operations and maintenance responsibilities including DIMP activities, that operator is responsible for complying with the pipeline safety regulations. 1. The operator does not have a DIMP written and implemented by August 2, 2011. 2. The DIMP does not contain the necessary procedures to demonstrate that the DIMP was written and is being implemented. 3. A new system was put into operation and service without a written DIMP. 4. An operator who acquired an existing system and did not continue operations under the existing DIMP or did not incorporate the acquired assets into its DIMP. Depending on the circumstances, some of the examples listed in this section may be inadequate plans and procedures, and not probable violations. Thus, the enforcement tool to address these issues would be a Notice of Amendment and not a Notice of Probable Violation or a Warning Letter. Section 3 of the Enforcement Procedures provides guidance on selecting the appropriate enforcement action. 1. Copies of the applicable pages of the DIMP showing that the operator has not clearly stated that the DIMP was written and implemented by August 2, 2011. 2. Documented oral and/or written statements from operator personnel. Page 9 <<>> Enforcement Guidance Revision Date Code Section Section Title Existing Code Language Origin of Code Last Amendment Interpretation Summaries Advisory Bulletin/Alert Notice Summaries Distribution Integrity Management Part 192 12/7/2015 §192.1007(a) What are the required elements of an integrity management plan? A written integrity management plan must contain procedures for developing and implementing the following elements: (a) Knowledge. An operator must demonstrate an understanding of its gas distribution system developed from reasonably available information. (1) Identify the characteristics of the pipeline's design and operations and the environmental factors that are necessary to assess the applicable threats and risks to its gas distribution pipeline. (2) Consider the information gained from past design, operations, and maintenance. (3) Identify additional information needed and provide a plan for gaining that information over time through normal activities conducted on the pipeline (for example, design, construction, operations or maintenance activities). (4) Develop and implement a process by which the IM program will be reviewed periodically and refined and improved as needed. (5) Provide for the capture and retention of data on any new pipeline installed. The data must include, at a minimum, the location where the new pipeline is installed and the material of which it is constructed. 192-113, 74 FR 63906, Dec. 4, 2009 192-116, 76 FR 5494, Feb 1, 2011 Advisory Bulletin ADB-12-06 - Issued May 7, 2012 PHMSA is issuing an Advisory Bulletin to remind operators of gas and hazardous liquid pipeline facilities to verify their records relating to operating specifications for maximum allowable operating pressure (MAOP) required by 49 CFR 192.517 and maximum operating pressure (MOP) required by 49 CFR 195.310. Advisory Bulletin ADB-12-05 – Issued March 23, 2012 PHMSA urges owners and operators to conduct a comprehensive review of their cast iron distribution pipeline systems and replacement programs and to accelerate pipeline repair, rehabilitation, and replacement of aging and high-risk pipe. In addition ADB notes regulation requirement for natural gas distribution companies to develop DIMP for pipelines owned, operated or maintained. Page 10 <<>> Advisory Bulletin ADB-11-01 – Issued January 10, 2011 PHMSA-2010-0381; Pipeline Safety: Establishing Maximum Allowable Operating Pressure or Maximum Operating Pressure Using Record Evidence, and Integrity Management Risk Identification, Assessment, Prevention, and Mitigation. Advisory Bulletin ADB-09-02 Issued September 30, 2009 Potential for issues with Weldable Compression Coupling Installation. Other Reference Material & Source Addressed in DIMP Final Rule preamble in Federal Register / Vol. 74, No. 232 / Friday, December 4, 2009 / Rules and Regulations at: • Comment Topic 20: Knowledge of pipeline. a. Environmental factors, Page 63919 Distribution Integrity Management FAQs • C.4.2 Can the DIMP plan incorporate by reference the operator’s procedures from their other manuals or plans? • C.4.a.1 The rule requires that an operator know its system. Must an operator excavate simply to gather information about parts of its system where it may not now have complete knowledge? • C.4.a.2 There are some characteristics about an operator’s system that may not be known during the development of the IM plan. What are PHMSA’s expectations for filling those voids? • C.4.a.3 Who qualifies as a “subject matter expert”? • C.4.a.4 What data will be required to be collected for new gas pipelines going in the ground? • C.4.a.5 What comprises "reasonably available" information? • C.4.a.6 Must an operator’s plan include the sources used to demonstrate an understanding of its gas distribution system? Gas Piping Technology Committee (GPTC) Guide Material Appendix G-192-8 • Section 3 Knowledge GPTC provides a useful list of records from which information is gathered. In addition to the information from the GPTC DIMP Appendix, the GPTC Guide Material Appendix G-192-17 contains a list of explicit requirements for reports, inspections, tests, written procedures, records and similar actions. Page 11 <<>> Guidance Information 1. The operator must have a written distribution integrity management plan (DIMP) that contains procedures for developing and implementing each requirement of §192.1007(a). The procedures must have adequate detail to clearly describe the manner in which each requirement will be met. The procedures need to provide a description of who, what, when, where, and how the operator will implement the elements. Operators must follow their procedures. The DIMP and any individual procedures documents should include management approvals, origin date, and the effective date of the last revision. For additional information, see the guidance section of §192.1005. 2. An operator must have knowledge of its natural gas distribution system including, but not limited to, the following characteristics: location, material composition, piping sizes, joining methods, construction methods, date of installation, soil conditions (where appropriate), operating and design pressures, history, operating experience performance data, condition of system, and any other characteristics noted by the operator as important to understanding its system. This information may be obtained from sources including system maps, construction records, work management system(s), geographic information system(s), corrosion records, and personnel who have knowledge of the system (Subject Matter Experts) 3. The operator must have a list of the information sources used to develop the DIMP. 4. The operator knowledge of the system should be focused on those characteristics which are needed to assess threats, evaluate risks to the system to identify risk reduction measures, and group facilities with like characteristics. An operator must begin by reviewing the data that characterizes its unique distribution system as the initial step in identifying threats and assessing and prioritizing the threats. Characteristics evaluated by the operator must allow the operator to identify facilities with known and potential problems. For example, operators should examine the design characteristic “joining method” to determine if their system contains mechanically joined pipe that could be a threat to the integrity of the system. 5. Operators who transport gases other than natural gas need to describe in their DIMP how the characteristics of the gas impact the threats and risk and include the differences from natural gas. 6. The term “environmental factors” has caused some confusion. As clarified in the DIMP Final Rule in response to Comment #20, environmental factors are “necessary to assess the applicable threats and risk to gas distribution pipelines and does not refer to consequences.” 74 Fed. Reg. 63906, 63919. The term “environmental” as used in the rule does NOT refer to “EPA” type environmental factors such as mercury regulators, PCBs, or contaminated soils (which require remediation when removed). It does refer to operating environment characteristics including but not limited to population density, landslide, corrosive soil, valve placement, seismic zones, flood zones, areas with wall-to-wall paving, frost impacts, geologic conditions, construction activities (significance of near-by construction), wash outs, types of soils, etc. Some of these factors will not apply to certain operators. An operator’s DIMP must include information about the environmental factors reviewed but does not need to describe the criteria they used to select them to develop the knowledge of their system. Page 12 <<>> Examples of a Probable Violation or Inadequate Procedures 7. The operator is required to have a list of the information sources used to develop the DIMP to demonstrate that they have considered all reasonably available records. All reasonably available records which provide information on a significant impact on system integrity must be included. 8. Some historical data may be no longer applicable to the current condition of the pipeline system. If the pipe was replaced, the data about the previous pipe may no longer be relevant. Such data may be relevant where the circumstances (e.g., construction practices, coatings, backfill materials, pipe materials, environmental conditions) of the pipe prior to replacement exist elsewhere and are relevant to existing risks in the operator’s system. For example, if bare steel pipe has been replaced, but some bare steel still exists in the system, then data concerning the replaced pipe may still be relevant. 9. If an operator acquires a pipeline and the historical records were not obtained or are not reasonably available, the records do not need to be recreated. However, this missing data must be identified as such within the operator’s DIMP, and a plan must be established for collection of relevant information. 10. Operators need to consider failures without a release to identify potential threats, and this type of information is considered reasonably available. For example, operators may evaluate where pressure regulators froze off and where upsets in the system could have occurred. 11. For data identified by the operator as needed for a threat identification and risk evaluation, there needs to be a process to identify facilities for which records are missing, inaccurate, or incomplete. 12. Collecting additional data and improving existing data is only required to occur as part of normal pipeline activities and over time. There must be a mechanism for individuals performing normal pipeline activities to know what additional data is needed. 13. Forms, recordkeeping procedures, data management systems and/or other methods used to collect information related to the physical attributes and/or operating and maintenance activities of distribution pipeline facilities should be appropriately modified to provide for the collection of reasonable available information. Personnel should be trained to properly collect and record the needed information and use the required forms. 1. The operator does not have a procedure that covers the tasks required. 2. The operator fails to follow the written procedures. 3. Operator did not demonstrate that they have looked at all reasonably available sources to find information from past design, operations, inspections, or maintenance activities. 4. Operator did not specifically list which documents were used to assemble knowledge of its system. 5. Operator does not gather or use reasonably available data on the entire pipeline that could be relevant to performing their threat assessment, risk evaluation or as needed to group like facilities. 6. DIMP did not identify the records containing the appropriate characteristics of the pipeline’s operating conditions to assess each threat category and subcategory to the operator’s pipeline. 7. DIMP did not identify the records containing the appropriate environmental characteristics to assess each threat category and subcategory to the operator’s pipeline. Page 13 <<>> Examples of Evidence Other Special Notations 8. There is no procedure for identifying needed missing, inaccurate or incomplete data. 9. The operator has not identified missing, inaccurate or incomplete data. 10. The operator has identified missing, inaccurate or incomplete data but does not have a procedure or plan to collect the missing data and information over time. 11. Operator failed to retain data on new pipeline installed. Depending on the circumstances, some of the examples listed in this section may be inadequate plans and procedures, and not probable violations. Thus, the enforcement tool to address these issues would be a Notice of Amendment and not a Notice of Probable Violation or a Warning Letter. Section 3 of the Enforcement Procedures provides guidance on selecting the appropriate enforcement action. 1. Copies of the applicable pages of the DIMP showing that the operator has not clearly stated the documents used to develop knowledge of the system. 2. The list of documents used to develop knowledge of the system is inadequate in identifying design, operating, or environmental characteristics of the pipeline system. 3. Copies of applicable pages of the DIMP showing that the DIMP is not detailed enough for an inspector to make a reasonable determination as to the accuracy and thoroughness of the process. 4. Documented photographic evidence demonstrating the violation. 5. Documented oral and/or written statements from operator personnel. Page 14 <<>> Enforcement Guidance Revision Date Code Section Section Title Existing Code Language Origin of Code Last Amendment Interpretation Summaries Advisory Bulletin/Alert Notice Summaries Distribution Integrity Management Part 192 12/7/2015 §192.1007(b) What are the required elements of an integrity management plan? A written integrity management plan must contain procedures for developing and implementing the following elements: * * * * * (b) Identify threats. The operator must consider the following categories of threats to each gas distribution pipeline: Corrosion, natural forces, excavation damage, other outside force damage, material or welds, equipment failure, incorrect operations, and other concerns that could threaten the integrity of its pipeline. An operator must consider reasonably available information to identify existing and potential threats. Sources of data may include, but are not limited to, incident and leak history, corrosion control records, continuing surveillance records, patrolling records, maintenance history, and excavation damage experience. 192-113, 74 FR 63906, Dec. 4, 2009 192-116, 76 FR 5494, Feb 1, 2011 Advisory Bulletin ADB-13-04 – Issued August 22, 2013 PHMSA advisory to alert all pipeline operators of a T.D. Williamson, Inc. (TDW) Leak Repair Clamp (LRC) recall issued by TDW on June 17, 2013. The recall covers all TDW LRCs of any pressure class and any size. The LRCs may develop a dangerous leak due to a defective seal. Hazardous liquid and natural gas pipeline operators should verify if they have any TDW LRCs subject to the recall by reviewing their records and equipment for installation of these LRCs. Advisory Bulletin ADB-13-03: Correction – Issued October 31, 2013 PHMSA is issuing an Advisory Bulletin to remind owners and operators of liquefied petroleum gas (LPG) and utility liquefied petroleum gas (utility LP-Gas) plants that although they must follow the American National Standards Institute/National Fire Protection Association (ANSI/NFPA) standards 58 or 59, they must also follow certain sections and requirements of Part 192. Advisory Bulletin ADB-13-02 – Issued July 12, 2013 PHMSA is issuing this advisory bulletin to all owners and operators of gas and hazardous liquid pipelines to communicate the potential for damage to pipeline facilities caused by severe flooding. This advisory includes actions that operators should consider taking to ensure the integrity of pipelines in case of flooding. Page 15 <<>> Advisory Bulletin ADB-12-05 – Issued March 23, 2012 PHMSA urges owners and operators to conduct a comprehensive review of their cast iron distribution pipeline systems and replacement programs and to accelerate pipeline repair, rehabilitation, and replacement of aging and high-risk pipe. In addition ADB notes regulation requirement for natural gas distribution companies to develop DIMP for pipelines owned, operated or maintained. Advisory Bulletin ADB-12-03 – Issued March 6, 2012 PHMSA advisory bulletin to alert operators using Driscopipe® 8000 High Density Polyethylene Pipe (Drisco8000) of the potential for material degradation. Advisory Bulletin ADB-11-05 – Issued August 26, 2011 PHMSA advisory to remind owners and operators of gas and hazardous liquid pipelines of potential for damage to pipeline facilities caused by the passage of Hurricanes. Advisory Bulletin ADB-11-04 – Issued March 20, 2012 Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Flooding. Advisory Bulletin ADB-11-02 – Issued February 9, 2011 Pipeline Safety: Dangers of Abnormal Snow and Ice Build-Up on Gas Distribution Systems. Advisory Bulletin ADB-10-03 – Issued March 24, 2010 Pipeline Safety: Girth Weld Quality Issues Due to Improper Transitioning, Misalignment, and Welding Practices of Large Diameter Line Pipe. Advisory Bulletin ADB-09-02 – Issued September 30, 2009 Potential for issues with Weldable Compression Coupling Installation Advisory Bulletin ADB-08-02 – Issued March 4, 2008 Issues Related to Mechanical Couplings Used in Natural Gas Distribution Systems Advisory Bulletin ADB-07-01 – Issued September 6, 2007 Updated Notification of the Susceptibility to Premature Brittle-like Cracking of Older Plastic Pipe Advisory Bulletin ADB-06-03 – Issued November 22, 2006 Notice to Operators of Natural Gas and Hazardous Liquid Pipelines to Accurately Locate and Mark Underground Pipelines Before Construction-Related Excavation Activities Commence Advisory Bulletin ADB-05-05 – Issued August 10, 2005 Inspecting and Testing Pilot-Operated Pressure Relief Valves Advisory Bulletin ADB-04-01 – Issued September 29, 2004 Hazards Associated with de-watering of pipelines Page 16 <<>> Other Reference Material & Source Advisory Bulletin ADB-02-01 – Issued May 24, 2002 Notice to Operators of Natural Gas and Hazardous Liquid Pipelines To Encourage Continued Implementation of Safe Excavation Practices Advisory Bulletin ADB-97-05 – Issued November 12, 1997 Potential Failure of Check Valves Following Remanufacturing Advisory Bulletin ADB-97-03 – Issued March 4, 1997 Potential Soil Subsidence on Pipeline Facilities Advisory Bulletin ADB-95-02 – Issued August 9, 1995 Increased Pipeline Transportation Security Measures Advisory Bulletin ADB-94-05 – Issued November 2, 1994 Pipelines Affected by Flooding Alert Notice ALN-92-01 – Issued January 8, 1992 Lightning-induced electrical discharge from tracer wire to plastic pipe. Alert Notice ALN-89-01 – Issued March 8, 1989 Update: Additional findings relative to factors contributing to operational failures of pipelines constructed by ERW prior to 1970 Alert Notice ALN-87-01 – Issued March 13, 1987 Incident involving the fillet welding of a full encirclement repair sleeve on a 14" API 5LX-52 pipeline; King of Prussia, PA 10/07/86 pipeline failure - **truncated:** true - **body characters:** 178316