2019-state-guidelines-revision3-final-appendices-2019-2-28

Guidelines for States Participating in the Pipeline Safety Program Revised January 2019 TABLE OF CONTENTS GLOSSARY v ACRONYMS xii Preface _ 1 The Federal/State Partnership 1.1 Congressional Intent _ 1.2 Federal Role and Organizational Structure _ 1.3 State Role and Organizational Structure _ 1.4 Related Organizations 1.4.1 1.4.2 National Association of Pipeline Safety Representatives _ National Association of Regulatory Utility Commissioners _ 1.5 Invitational Travel _ 1.6 Mutual Aid _ State Participation Requirements 2.1 Section 60105 Certification 2.2 Section 60106 Agreement 2.3 Interstate Agent Agreement 10 2.4 Time Defined Agreement _ 11 2.5 Joint Inspection of an Interstate Operator _ 11 2.6 Certification/Agreement Forms _ 12 2.7 Progress Report 12 2.7.1 2.7.2 2.7.3 2.7.4 2.7.5 2.7.6 2.7.7 2.7.8 2.7.9 2.7.10 Attachment #1: State Jurisdiction and Agent Status 12 Attachment #2: Total State Field Inspection Activity _ 13 Attachment #3: Facilities Subject to State Safety Jurisdiction 13 Attachment #4: Pipeline Incidents/Accidents _ 13 Attachment #5: State Compliance Actions _ 14 Attachment #6: State Record Maintenance and Reporting _ 14 Attachment #7: State Employees Directly Involved in the Pipeline Safety Program _ 14 Attachment #8: State Compliance with Federal Requirements 14 [RESERVED] _ 14 Attachment #10: Performance and Damage Prevention Questions _ 14 State Regulatory Responsibility _ 16 3.1 Adoption of Federal Regulations and Requirements 16 3.2 Waiver of Federal Regulations 16 3.2.1 3.2.2 Interstate Pipelines 16 Intrastate Pipelines 16 Personnel 19 4.1 4.1.1 4.1.2 4.1.3 4.1.4 State Agency Minimum Required Inspection Activity _ 19 Determination of Inspection Activity _ 19 Peer Review _ 22 Inspection Activity Examples _ 22 Determination of Recommended Inspection Person-Days CY2017 23 Guidelines for States Participating in the Pipeline Safety Program Revised January 2019 i TABLE OF CONTENTS 4.1.5 Updates to SICT _ 23 4.2 Allocation of Effort 28 4.3 Training _ 28 4.3.1 4.3.2 4.3.3 4.3.4 Required Training 28 Course Re-Testing 31 Waivers from Training 32 Procedures for Requesting a Training Waiver _ 32 4.4 Continuing Education and State Inspector Mentoring Program _ 33 4.5 Changes in State Program Personnel _ 33 4.6 Individual Qualifications _ 34 4.7 Program Manager Training 36 4.8 New Program Manager Orientation 36 Inspection and Compliance Program 38 5.1 Inspection _ 38 5.2 Compliance 46 5.2.1 5.2.2 5.2.3 5.2.4 Procedures for State Agencies with a Section 60105 Certification _ 46 Procedures for State Agencies with a Section 60106 Agreement or Interstate Agents 47 PHMSA Orders to Operators 47 Referring Concerns of Possible Criminal Activity to the Office of Inspector General (OIG): 47 Failure Investigation and Safety-Related Conditions _ 48 6.1 Investigation of Pipeline Failures 48 6.2 On-scene investigations 49 6.3 Basic Investigative Procedures 52 6.4 Incident Investigation Procedures _ 52 6.5 PHMSA AID Daily Telephonic Investigation Report 52 6.6 Access to NRC Reports 53 6.7 Safety-Related Conditions 54 Damage Prevention Program and One Call Notification 55 7.1 Damage Prevention _ 55 7.2 One Call Notification 56 7.3 Damage Prevention and One-Call Grants _ 58 State Agency Program Performance _ 59 8.1 Annual Program Evaluation 59 8.2 Compliance with Program Requirements _ 61 8.3 Recordkeeping _ 62 8.4 Attendance at NAPSR Meetings _ 62 8.5 State Pipeline Safety Training and/or Seminars 63 Guidelines for States Participating in the Pipeline Safety Program Revised January 2019 ii TABLE OF CONTENTS DOT Grant-in-Aid Program _ 64 9.1 Scope of Grant _ 64 9.2 Address _ 64 9.3 Eligibility 64 9.4 General Obligations _ 65 9.5 Application 65 9.5.1 9.5.2 Attachment #1: Description of State Pipeline Safety Program 65 Attachment #2: Pipeline Safety Program Estimated Budget _ 67 9.6 Annual Funding Level _ 67 9.7 Grant Allocation and Percentage of Funding 67 9.7.1 9.7.2 Grant Allocation Formula for Grant Award 68 State Performance Score _ 68 9.8 Payment Agreement (Notice of Grant Award) _ 71 9.9 Certification Regarding Lobbying and Disclosure of Lobbying Activities _ 72 9.10 Mid-Year Request for Reimbursement _ 72 9.11 Request for Advance Payment - Travel to NAPSR Meetings 73 9.12 Year-end Request for Reimbursement and Cost Summary _ 73 9.13 Special Initiatives _ 74 9.14 Withholding of Grant Funds - Suspension and/or Termination of Grants _ 74 9.15 Deposit of Grant Funds 75 9.16 Eligibility of Program Costs 75 9.16.1 9.16.2 9.16.3 9.16.4 9.17 Direct Costs _ 75 Indirect Costs 78 Standards for Documentation of Personnel Expenses _ 79 Unallowable Costs 79 Pipeline Safety Grant Program Review _ 79 9.17.1 9.17.2 9.17.3 9.17.4 9.17.5 Pre-Review 80 Grant Review 80 Post-Review _ 80 Adjustments and Penalties 80 Appeal of Findings 81 9.18 Procurement Standards 81 9.19 Procurement Procedures _ 81 9.20 Contracts Management 81 9.21 Internal Controls _ 81 9.22 Real Property 82 9.23 Personal Property _ 82 9.24 Code of Conduct 82 9.25 Conflict of Interest and Mandatory Disclosures 82 Guidelines for States Participating in the Pipeline Safety Program Revised January 2019 iii TABLE OF CONTENTS 9.26 Audit Requirements (2 CFR 200 Subpart F) _ 82 9.27 PHMSA Office of Civil Rights Review – Title VI _ 83 9.28 Grant-in-Aid Program Calendar of Events 84 9.29 Description of Activities 85 9.29.1 9.29.2 9.29.3 9.29.4 9.29.5 9.29.6 9.29.7 9.29.8 9.29.9 9.29.10 10 Base Grant Application (Gas & Hazardous Liquid) _ 85 One Call Grant _ 85 Year End Payment Process 85 One Call Progress Report _ 85 One Call Allocation _ 85 Progress Report 85 Allocation _ 85 Payment Agreement – (Notice of Grant Award) _ 85 Mid-Year Reimbursement 86 Program Evaluation 86 Federal-State Tracking and Reporting – “FedSTAR” _ 87 10.1 Purpose _ 87 10.2 Location and Procedures _ 87 10.3 Facilitating Various Program Documentation 88 10.4 Facilitating Grant Financials 88 10.5 Other FedSTAR Functions _ 90 10.6 PHMSA State Program Management Functions _ 90 Appendix Summary 91 Guidelines for States Participating in the Pipeline Safety Program Revised January 2019 iv Glossary GLOSSARY Act See Chapter 601, Title 49 of the U.S Code (2011 version) Agency See State Agency Agreement The State agency assumes inspection responsibility for facilities and reports probable violations to PHMSA for compliance action Certification The State agency assumes safety responsibility with respect to intrastate facilities over which it has jurisdiction under State law Certification Regarding Lobbying Each grantee who receives a Federal grant exceeding $100,000 must submit a certification form CFDA Catalog of Federal Domestic Assistance A reference compilation of all grant programs sponsored by the Federal government PHMSA’s CFDA number is 20.700 for the Pipeline Safety Grant Program Chapter 601, Title 49 of the U.S Code (2016) Throughout this manual, Sections 60101 – 60140 refer to Chapter 601, Title 49 of the United States Code (2016) Chapter 601 is the recodification of the Natural Gas Pipeline Safety Act of 1968, as amended (49 USC app 1671 er seq.), and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (49 USC app 2001 er seq) Code of Federal Regulations, Title 49 (49 CFR)-Pipeline Safety Part 40 Procedures for Transportation Workplace Drug Testing Programs Part 190 Pipeline Safety Programs and Rulemaking Procedures Part 191 Transportation of Natural and Other Gas by Pipeline: Annual Reports Incident Reports, and Safety-Related Condition Reports Part 192 Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards Part 193 Liquefied Natural Gas Facilities: Federal Safety Standards Part 194 Response Plans for Onshore Oil Pipelines Part 195 Transportation of Hazardous Liquids by Pipeline Part 196 Protection of Underground Pipelines from Excavation Activity Guidelines for States Participating in the Pipeline Safety Program Revised January 2019 v Glossary Part 198 Regulations for Grants to Aid State Pipeline Safety Programs Part 199 Drug and Alcohol Testing Compliance Action An action or series of actions taken to enforce Federal pipeline regulations These actions may take the form of a warning letter, an administratively imposed monetary sanction or order directing compliance with the regulations, an order directing corrective action under hazardous conditions, a show cause order, a criminal sanction, a court injunction, or a similar formal action Department of Transportation (“DOT”) Reference may include any or all of the following: U.S Department of Transportation, Pipeline and Hazardous Materials Safety Administration, Office of Pipeline Safety Federal State Tracking and Reporting (“FedSTAR”) This is the computer application available over the internet which is used by Pipeline Safety program offices to enter the required federal documentation and information Grant Funds or aid in kind to carry out specified programs, services, or activities Grant Agreement All provisions and requirements of the Pipeline Safety Grant Program, including those specified in the Grant Application, Payment Agreement (Notice of Grant Award), these Guidelines, and any instructions or directives issued by the PHMSA, DOT, or other Federal agency relative to the management of Federal grant programs Grant Application This form is to provide PHMSA with information concerning the State agency’s need for Federal financial support for its pipeline safety program Grantee The department or agency of State government which is responsible for the administration of the pipeline safety grant Also referred to as “recipient” or “State agency.” Grant Period The grant period extends from the effective date of the Payment Agreement (Notice of Grant Award), January 1, to the expiration date, December 31, unless otherwise arranged Also referred to as the “program year.” Grants.gov Grants.gov is a central storehouse for information on federal grants Grant Program Those activities and operations of the State agency which are necessary to carry out the purposes of the grant, including any portion of the program financed by the grantee This technical usage of the phrase should not be confused with the Pipeline Guidelines for States Participating in the Pipeline Safety Program Revised January 2019 vi Glossary Safety Grant Program (sometimes shortened to “Grant Program”), which is the Federal assistance program in support of the State agency’s pipeline safety program Inspection, Standard An on-site evaluation of an inspection unit for compliance with all applicable Federal or State standards This includes a thorough compliance review of the operator’s plans, procedures, programs, records, physical plant, and work in progress This would include inspections on LNG facilities See Chapter for guidance Inspection Person-Day All or part of a day spent by Agency staff – Supervisor(s) and/or Inspector(s)/Investigator(s) (including travel) in on-site evaluation of an operator’s system to determine compliance with Federal or State pipeline safety regulations; or in on-site investigation of a pipeline incident; or in job-site training of an operator (See section 5.1 for description of inspection types) Time counted for such activities should be reported as a maximum of one inspection person-day for each day devoted to safety issues, regardless of the number of operators visited during that day (e.g You may evaluate two operators in the same day and record each inspection visit as 0.5 person-day, or actual fraction of a day, for each operator provided the total does not exceed 1.0 person-day) On a limited basis, the inspector may count in-office inspection time to review operator written: plans, procedures, programs and records in order to effectively use on-site inspection time, as approved by the program manager and as noted in the annual progress report In-office inspection time must be adequately documented and made part of the state program’s inspection records Inspection Unit All or part of an operator’s pipeline facilities under the control of an administrative unit that provides sufficient communication and controls to ensure uniform design, construction, operation, and maintenance procedures for the facilities The application of the inspection unit concept will ensure inspection coverage of an operator’s entire system and enhance Federal/State management of work load and program evaluation Determination of inspections will be based on the following guidelines, but where unique situations exist, good logic and judgment must be exercised when identifying the parameters of the unit  Privately Owned Distribution System The inspection unit could be an operating area such as a specific city or metropolitan area, or a group of towns, and may include high pressure distribution operated and maintained by the operator The unit selected should be that which provides the desired commonality However, because of the greater number of pipeline facilities in some large metropolitan distribution areas, multiple units may be appropriate In selecting the unit, consideration Guidelines for States Participating in the Pipeline Safety Program Revised January 2019 vii Glossary should be given to the size of the area covered, work location, record location, and line of supervision If the distribution system contains transmission lines where transmission integrity management plans are required, those system(s) should be considered separate intrastate transmission inspection unit(s)  Gas Transmission and Hazardous Liquid Pipeline System (including Ethanol) The inspection unit should include up to 500 miles of pipeline right-of-way including any compressor stations or pumping facilities within the designated limits In some circumstances, such as densely populated areas and/or environmentally sensitive areas, and/or where judged necessary based on local conditions, a separate inspection unit can be established  Liquefied Natural Gas (LNG) Facility Each LNG facility should be considered a single inspection unit  Master Meter System Each master meter system should be considered a single inspection unit However, more than one master meter system should be considered a single inspection unit if all facilities involved are owned, operated and maintained under common supervisory control  Municipality Each municipality should be considered a single inspection unit unless its system, similar to privately owned distribution systems, contains transmission lines where transmission integrity management inspections are done in which case the transmission system should be a separate inspection unit Also operating conditions/characteristics could suggest additional inspection units be considered  Propane-Air System/Petroleum Gas System Propane-Air System/Petroleum Gas System- Each system should be considered a single inspection unit However, more than one propane-air/petroleum gas system should be considered a single inspection unit if all facilities involved are owned, operated and maintained under common supervisory control  Regulated Gathering Pipeline System Each regulated gathering pipeline system can be considered as a single inspection unit Circumstances may exist when an operator has more than one regulated gathering system separated into individual inspection units Interstate Agent The State agency assumes inspection responsibility for interstate facilities and reports probable violations to PHMSA for compliance action Guidelines for States Participating in the Pipeline Safety Program Revised January 2019 viii Glossary Mid-year Request for Reimbursement If a State desires mid-year payment, it may return one copy of a completed OMB Standard Form 270 to PHMSA requesting a mid-year payment Modifications to Payment Agreement (Notice of Grant Award) Used to amend the Federal grant amount in the Payment Agreement (Notice of Grant Award) National Response Center (NRC) (1-800424-8802) The federal government’s national communications center, which is staffed 24 hours a day by U.S Coast Guard officers and marine science technicians The NRC receives all reports of releases involving hazardous substances and oil that trigger the federal notification requirements under several laws This “telephonic” report data is shared with PHMSA via an information system National Transportation Safety Board (NTSB) This Federal agency was created by Congress in the Department of Transportation Act of 1966 Although NTSB’s authority is limited to transportation failure investigations, its mission relating to pipeline safety is to: Investigate significant failures and report the circumstances relating to each failure and its probable cause Make recommendations to the Secretary, the pipeline operators, manufacturers, associations, and interested parties in order to minimize the possibility of recurrence of similar failures Release reports deemed to be in the public interest Conduct special studies and investigations on matters regarding safety in pipeline transportation and failure prevention Noncompliance A violation or probable violation of any section or any subsection of Federal or State pipeline safety regulations Office of Pipeline Safety (OPS) For the purpose of this manual, OPS is the U.S Department of Transportation, Pipeline and Hazardous Materials Safety Administration’s Office of Pipeline Safety OMB Standard Form 270-Request for Advance or Reimbursement Submitted by a State agency for Mid-Year Request for Reimbursement, Year-end Request for Reimbursement, and Request for Advance Payment - Travel to NAPSR Meetings Guidelines for States Participating in the Pipeline Safety Program Revised January 2019 ix Example Pipeline Safety Program Plan the NOPV form and warning letter Upon completion of the associated report, the NOPV form, and NOPV letter, the violation will be logged onto an Excel spreadsheet maintained on the [designated file location] The spread sheet contains multiple sheets including outstanding violations and corrected violations Once updated the outstanding NOPV sheet is printed and posted on the Pipeline Safety bulletin board Follow-up inquiries will be made to the violation issues Each violation will receive follow-up on a quarterly basis The update should be conducted on the first Monday of the new quarter If the Inspector is absent on the first Monday of the new quarter, the follow-up shall be conducted the day the Inspector returns to the office The actions to be conducted during the follow-up activities shall include: a review of the NOPV form, NOPV letters and associated documents; updating the NOPV Status form stored on the [designated file location]; printing the updated NOPV Status form; attaching the printed copy of the NOPV Status form to the NOPV file packet, and returning the updated packet to the Pipeline Safety Administrator for logging on the Excel spread stored on the [designated file location] The extent of the follow-up will be determined by the nature and severity of the violation Examples of follow-up actions:  Periodic contact with the operator to determine corrective actions,  Confirmation of corrective actions at specific time intervals determined by the Inspector or Program Manager, possibly including field verification,  Review and confirmation during next regularly scheduled inspection,  Citation Order/Civil Penalty U Closure of a Probable Violation Under normal circumstances closure of a notice of probable violation may be accomplished by one of the follow:  The operators response to the NOPV letter includes documentation of correction of the deficiency;  A follow-up inspection has been conducted to verify correction of the deficiency;  A regularly schedule inspection of the operator has verified the violation issue no longer exists The process of correcting a NOPV will require the Inspector to document the corrective actions taken by the operator to correct the deficiency and actions taken by the Inspector to verify corrective actions This can be in the form of a Report, O&M Plan review report, or updating the NOPV Status form The Inspector will also obtain the original NOPV form from the [state pipeline safety agency] files and note on the form that the NOPV issue has been corrected as well as the date of verification The entire package containing the NOPV notification form, NOPV letter, NOPV status form if applicable, and corrective action report shall be submitted to the Program Manager The Program Manager will review all documentation to determine if acceptable actions have been taken and the violation can be removed or corrected If the corrective actions are acceptable to the Program Manager the entire package will be provided to the Pipeline Safety Program Administrator for appropriate documentation and filing V Issues Identified Page 22 of 36 Example Pipeline Safety Program Plan Occasionally, an Inspector may observe conditions or operating practices that are not violations at the time, but could, if not corrected, result in a future violation or an unsafe situation On those occasions, the inspector should verbally inform the operator of the potential problem, and also include the issue in the Report or Post Inspection Memorandum A copy of the report will be provided to the operator after review by the Pipeline Safety Program Manager If the Inspector uses the Issues Identified in lieu of a noncompliance form for minor violations, it should only be used after considering all potential public safety concerns (risk) and the action being taken by the operator to correct the problem Minor Violation Examples:  A record keeping error when an item of maintenance was not properly recorded, but which presents no immediate safety problem unless a set series of events would occur to the gas system operation  An operational or maintenance deficiency, which may involve equipment or facilities, not used as the primary safety protection for the pipeline  A deficiency that is not considered unsafe, but has never been formally addressed before with operator  An issue brought to the attention of the Inspector by the operator prior to the inspection The Issue Identified option should only be used after the inspector has considered all safety concerns and the operator's past performance for correcting apparent violations Page 23 of 36 Example Pipeline Safety Program Plan VI Investigation of Incidents The PHMSA State Guidelines, section 5.1.3 requires that state agencies have written procedures that provide for methodical, systematic, comprehensive, and consistent investigation of incidents and accidents This section contains examples of administrative procedures which provide State agencies with additional specificity regarding PHMSA’s expectations for the level-of-detail appropriate in such procedures A Background The [insert State agency name] enforces safety standards for the transportation in [insert State name] of hazardous liquid and/or natural and other gas by pipeline pursuant to the [insert State statute] The State agency has adopted and maintained rules establishing minimum safety standards that are at least as inclusive, as stringent, and compatible with the minimum safety standards adopted by the Secretary of Transportation under the Federal Act The State agency’s Pipeline Safety Program conducts on-site inspections of the approximately [xxx] gas operators to determine compliance with all applicable federal and/or state regulations Inspectors monitor operator records concerning inspection, operation, maintenance, emergency procedures, and construction Inspectors also conduct field inspections of operator facilities to verify compliance with regulations covering design, construction, operation and maintenance of the pipeline facilities Under the State agency’s certification agreement with the U.S DOT, the State agency must investigate all incidents involving operator procedures or facilities resulting in (1) death, (2) injury requiring hospitalization, or (3) property damage in excess of $50,000 Additionally, incidents which not satisfy one of these three thresholds may be investigated if the circumstances are unclear or if staff believes operator procedures or facilities may have contributed to or caused of the incident Where uncertainty exists, inspections are done B General Procedures Pipeline owners and operators are required to report all incidents which are the result of gas leaking from their facilities and which resulted in death, personal injury requiring in-patient hospitalization, or property damage of $50,000 or more Additionally, gas system owners and operators must inform the Pipeline Safety Program of incidents which not meet these criteria, but may be important to communicate for other reasons (media attention, explosions not involving natural gas, location, etc.) When the Pipeline Safety Program is notified of such incidents, we must decide if (1) an investigation is required (three criteria above, except property damage limit for an investigation is $50,000), (2) not required but prudent, or (3) unnecessary The Pipeline Safety Program’s role in accident investigations is to determine the cause of the incident, or probable cause, and make recommendations, which will prevent a recurrence When it appears that a safety violation contributed to the incident, the Pipeline Safety Program may make recommendations to the State agency for enforcement actions in the form of show cause hearings and probable penalty assessment The scope of the investigation, therefore, is important to provide assurance that the findings, recommendations and follow-up activities contribute to public safety The initial response involves deciding whether to make an immediate inspection, a delayed inspection Page 24 of 36 Example Pipeline Safety Program Plan or no inspection at all, who should make the inspection, and who should be informed The scope of an investigation involves deciding which staff will participate, the initial activities, and then, with preliminary results in hand, developing a plan and schedule for completing the investigation and report (Reference Codified State Requirement if applicable), the pipeline operator is required to give telephonic notice of all incidents caused from gas escaping from pipeline facilities resulting in property damages exceeding $50,000, injury requiring overnight hospitalization, or a fatality The State agency has established a Pipeline Safety Emergency Line for the reporting of incidents, the number is (xxx) 5555555 The line is monitored 24 hours a day, 365 days a year, by Pipeline Safety Program staff during working hours and a contracted answering service on nights, weekends and holidays The answering service takes the message and then calls the Pipeline Safety Program Manager, or, in his absence, the assigned Inspector This is usually done within an hour of the incident The operator is immediately contacted for more detailed information An hour is usually not enough time for a pipeline operator to complete all the inspections and testing of gas system facilities to confirm whether their facilities are or are not involved in a reported incident Although additional information may not be available at the time, a communications link is established to keep Pipeline Safety Staff informed as information becomes available Each incident is different, but the information surrounding each incident must be analyzed to determine whether an on-site inspection is necessary This analysis is based on Federal reporting criteria, operational knowledge of the facilities and experience in these matters If it is immediately evident that the probable cause of the incident was not on gas company facilities or there is indication that arson is involved, we would only investigate if the operator requests assistance Incidents involving customer inside piping go beyond our jurisdictional responsibility and therefore not require us to investigate Generally, operators notify Pipeline Safety Staff of all incidents, whether or not they meet one of the aforementioned three criteria, which require reporting (the threshold for property damage is $50,000 for reporting purposes) This is done as a courtesy to give us prompt notice, to inform us of media coverage and is a safe approach to reporting Ultimately, we decide, based on the information received, whether it is necessary to visit the site The Pipeline Safety Program is not designed to be a front line responder The Pipeline Safety Program serves a monitoring function Our accident investigations are designed to ensure that the gas system operator has conducted a thorough investigation into the circumstances surrounding any incident and, based on that information, the gathering of evidence from on-site inspections and from other sources, including fire and arson investigators, to determine the probable cause of an incident To make better use of time and resource, and allow the operator time to gather the needed documentation, Pipeline Safety Staff’s response may be delayed for a few days An example of this would be an incident caused by excavator damage to a pipeline resulting in property damage When Pipeline Safety does decide to investigate an incident, the purpose is to determine the cause, or probable cause, as required by the Federal Pipeline Safety Act for certification, and to make Page 25 of 36 Example Pipeline Safety Program Plan recommendations for improvements and corrections If an investigation reveals evidence of wrongdoing, or violation of the [insert State statute], Pipeline Safety Staff may proceed with informal hearings, or recommend formal show-cause actions including civil penalties, whichever is deemed appropriate Pipeline Safety Staff then monitors the operator’s corrective actions in response to the recommendations, and any noncompliance issued resulting from the incident, through follow-up inspections The Pipeline Safety Program Manager will assign an Inspector to investigate any incident deemed to qualify as a requirement as reportable under State or Federal law If it is a major incident involving several injuries or fatalities, more than one Inspector may be assigned to investigate Depending on the magnitude of the incident the Pipeline Safety Program Manager may coordinate the on-site investigation The operator may be required to perform a root cause analysis of the incident in certain situations Examples of such situations are:    Staff determines that the operator has done a poor evaluation of the incident cause Staff does not agree with the incident cause stated by the operator Staff does not agree with NTSB conclusions (if applicable) In some instances, incidents may be reported but no on-site investigation may be warranted upon receipt of additional information In those instances, a memo to the Incident File will be created documenting the reason(s) that an on-site investigation was not conducted C Initial Issues to Note in Response to an Incident Report D Operator responsibility for reporting Death, or injury requiring hospitalization, damage level Scope of Incident Decision to send staff to Incident site Communicating with appropriate State agency, PHMSA, and NTSB individuals if necessary Internal (agency) communication of incidents/staff response Other Incident Investigation Process and Scope On-site inspection of company facilities Review of company records (odorant levels, leak calls, etc.) Interviews Coordination with others (OSFM, NTSB, fire, police et al.) Determination of cause/probable cause Review preliminary findings Schedule Report preparation Page 26 of 36 Example Pipeline Safety Program Plan Staff’s Standard Operating and Enforcement Procedures, specifically Accident Investigations 10 Awareness of the possibility of litigation 11 Other E Telephone Notification Pipeline owners or operators are required to report to the State agency all accidents which result from gas leaking from gas distribution and transmission facilities and which caused death, personal injury requiring hospitalization, or property damage of $50,000 or more Under our certification agreement with U.S Department of Transportation, the State agency is required to investigate and report on all accidents resulting in death, personal injury requiring hospitalization, or property damage of $50,000 or more [List any other applicable state issues here] The gas distribution system does not include fuel line or appliance piping inside the building F Specific Investigation Issues - All Incidents/Accidents All incident investigations should be completed using Incident Investigation Checklist – See Appendix C The information collected should include, but not necessarily limited to the following items The checklist should encourage a more thorough investigation 10 11 12 G Record the location, city, street and number, date and time, occupant name(s), name(s) of injured and/or fatalities and estimated amount of property damage Nature of accident - explosion, fire, rupture, etc Indicate cause - third party, human error, etc Date and time of notification to the company, how received, who received and who reported Time company personnel arrived at the location Conditions found at time of arrival Action taken by company personnel If gas was escaping, time and method of securing Take photographs, including close ups of any exposed gas facilities and buildings involved It is recommended that you record the sequence of photos taken as you proceed, identifying the pictures and what you wish to depict Statements of company personnel, public and private witnesses and/or investigating or responding parties who may have information relative to the accident Determine apparent cause if determination probable cause cannot be made (A statement that a certain piece of equipment failed is not the cause; determine what caused the failure of the particular piece of equipment) Utilize the accident investigation guide (checklist) as applicable Statement of investigation activities and recommendations for prevention of future occurrence Additional Issues, If Required Make a drawing of the area showing the boundaries of gas in the ground and the degree Page 27 of 36 Example Pipeline Safety Program Plan of the leaking gas from the point of the leak Show bar-hole pattern description, location of pipes, buildings and streets Copies of pressure charts of the portion of the system involved Age, size and type of facilities involved, location and condition of isolation valves Corrosion control records and odorant test records Leakage survey data of area involved - dates, number and class of leaks and disposition Leak and repair history of facilities in the surrounding area If third party damage, location and marking data, time of request for location, time and method of marking Inspection and maintenance program relative to facilities involved and degree of compliance Metallurgical analysis 10 Pressure test records 11 Pipe and material specifications, welding and welder qualification data 12 New construction specifications, contractor or company installation 13 Description of metal break with respect to: a) Displacement and what may be the cause - measure angle and state plane of maximum deflection b) Degree of parting c) Evidence of corrosion, pitting, wall thickness uniformity, pipe coating d) Shear or tensile break or combination There is the possibility of litigation in all accidents, and you may be called as a witness With this in mind, your report should contain the facts as you find them and your conclusions should be supported by accurate documentation Our role in accident investigations is to determine the probable cause of the accident, if possible, and make recommendations, which will prevent recurrence Accurate documentation should support any determination made It is recommended that the inspector use the PHMSA incident investigation form Page 28 of 36 Example Pipeline Safety Program Plan Appendix A – Operator List [insert operator list] Page 29 of 36 Example Pipeline Safety Program Plan Appendix B – Example Risk Based Inspection Prioritization Model for Gas Transmission To prioritize gas transmission operators using a risk-based approach, a set of risk factors have been developed based on existing data readily obtained from gas operator annual reports, incident reports, leak history data, and semi-annual performance metrics The methodology is based on the following factors:  Actual events that have occurred on an operators system  Pipeline characteristics that could indicate a potential to impact HCAs  Historical operator performance in areas related to pipeline integrity Some of the indices are indicators of the likelihood of accidents and some relate to the potential consequences of accidents The algorithm used to calculate each index is designated accordingly Index #1: Releases That Resulted in Major Impacts Data on actual events that have occurred on an operator’s pipelines can be found in both the Incident Report and the Annual Report The Annual Report requires the operator to report leaks An incident report is required to be submitted to PHMSA if there is a release of gas from a pipeline and:  There have been fatalities, or  There have been injuries requiring in-patient hospitalization, or  There has been property damage exceeding $50,000, or  The event is significant, in the judgment of the operator, even if it did not meet any of the other criteria The inputs to the model from Incident Reports submitted by an operator are:  The number of incidents in the past three years that have resulted in fatalities  The number of incidents in the past three years that have resulted in injuries that required inpatient hospitalization  The number of incidents in the past three years that have resulted in property damage reported to OPS The number of incidents in each of these three categories is then multiplied by a weighting factor assigned to fatalities, injuries, and property damage The weighting factors used are:  Fatalities - 10  Injuries but no fatalities -  Property damage only (no injuries or fatalities) – Total pipeline mileage is used to normalize the incident data, since large systems will likely have more incidents than smaller systems A comparison of the relative integrity performance among operators is therefore normalized based on total system mileage (unitized to 1000) Index #2: Releases That Resulted in Minor Impacts Releases that result in minor impacts are leaks that are below the threshold that would trigger an incident report Leaks not result in fatalities or injuries or in significant property damage The Gas Annual Report requires that leaks be reported by cause The data from available annual reports is used in the risk-based prioritization methodology The parameters to be input into the model from the Gas Annual Report are: Page 30 of 36 Example Pipeline Safety Program Plan  The number of leaks caused by corrosion  The number of leaks caused by natural forces  The number of leaks caused by excavation  The number of leaks caused by other outside forces  The number of leaks caused by material and welds  The number of leaks caused by equipment and operations  The number of leaks caused by “other” causes The weighting factor for all leaks is This maintains the relative importance of leaks compared to incidents which have higher weighting factor multipliers Total pipeline mileage is again used to normalize the leak data This index is related to the likelihood of leaks occurring in the future based on past performance Index Group #3: Pipeline Characteristics Indicative of Relative Risk The Gas IM Semi-Annual Performance Metrics Report and the Annual Report require each gas operator to report on pipeline characteristics that are directly related to the potential for a pipeline to impact an HCA The Gas IM Semi-Annual Performance Metrics Report requires the operator to report total pipeline miles, total HCA miles, miles assessed, number of immediate repairs performed, and number of scheduled repairs performed The Annual Report requires the operator to report the number of miles for a range of pipe diameters; the number of miles by age of the pipeline; the number of miles of steel pipe that are cathodically protected versus unprotected; and the number of miles in each category that are bare versus coated All of these parameters can be correlated to the potential for an operator’s pipelines to impact an HCA The higher the number of HCA miles, the greater the potential for an HCA to be impacted A high number of immediate repairs could reflect a deteriorated pipeline condition and a correspondingly higher likelihood for HCA impact Bare, unprotected steel pipe is at a higher risk of corrosion than is coated, cathodically protected pipe Large diameter pipe results in a greater Potential Impact Radius (PIR) than does smaller diameter pipe at the same MAOP, reflecting a larger area of potential impact The period in which a pipeline was constructed and the pipe manufactured is indicative of the type of seam weld and reliability of the manufacturing process, as well as the likelihood of injurious defects existing in the pipe Index #3.1: Total Covered Segment Mileage The input into the risk model from the Gas IM Semi-Annual Performance Metrics Report is total HCA miles Covered segment mileage in a pipeline system is directly proportional to the likelihood of (exposure to) high consequence incidents Index #3.2: Immediate and One-Year Repairs Made An immediate repair is expected to be the exception rather than the rule Immediate repairs may be indicative of deteriorating pipeline integrity The input into the risk model from the Gas IM Report is:  Number of Immediate Repair Conditions (NIRC)  Number of Scheduled Repair Conditions (NOYRC) In addition, covered segment mileage with completed assessments is used to normalize the repair data, since operators with many completed assessments will likely have reported more repairs than operators with fewer Page 31 of 36 Example Pipeline Safety Program Plan completed assessments A comparison of the relative integrity performance among operators is thus based on total covered segment mileage that has been assessed (unitized to 1000 total pipeline miles) Scheduled repairs are weighted 1/10 the value of immediate repairs Index #3.3: Diameter of Pipe The pipeline in an operator’s system is usually of various diameters The Potential Impact Radius (PIR) is directly proportional to the diameter of the pipe Large diameter pipe is therefore assumed to pose a higher potential risk than is smaller diameter pipe Pipeline diameter, by miles, is reported by the operator in the annual report The ranges reported are >28 inch, >20 to 28 inch, >10 to 20 inch, >4 to 10 inch, inch or less, and unknown The inputs into the risk model from the Annual Report and the associated assigned weighting factors are:  The number of miles of pipe >28 inch 10  The number of miles of pipe >20 inch to 28 inch  The number of miles of pipe > 10 inch to 20 inch  The number of miles of pipe >4 inch to 10 inch  The number of miles of pipe inch or less  The number of miles of pipe of unknown size 10 The index score assigned is based on the ratio of miles of pipe in a given diameter range to the total miles of pipe in an operator’s system The index is then the sum of the index score for each populated range Pipe of unknown diameter is conservatively assumed in the model to be in the > 28-inch range Index #3.4: Age of Pipe Pipe materials and manufacturing techniques have improved steadily over time Older pipe was generally manufactured with lower quality materials and under less strict quality control methods than those used in later years Pipelines constructed before 1970 could have flash welded, lap welded, or Low Frequency ERW seams that are known to be less reliable Pipelines constructed from 1970 to the present day were primarily constructed using High Frequency ERW, Single and Double Submerged Arc Welds, Spiral Welds, or are seamless In addition, older pipe has had more time to develop defects such as corrosion, coating deterioration, CP interruptions, undetected instances of third party damage, outside forces due to soil instability or ground movement, etc The inputs into the risk model from the Annual Report and the associated assigned weighting factors are:  The number of miles constructed in the period 2000-2009  The number of miles constructed in the period 1990 – 1999  The number of miles constructed in the period 1980 – 1989  The number of miles constructed in the period 1970 – 1979  The number of miles constructed in the period 1960 – 1969  The number of miles constructed in the period 1950 – 1959  The number of miles constructed in the period 1940 – 1949  The number of miles constructed in the period pre 1940 10  The number of miles of unknown construction period 10 Pipe of unknown construction period is conservatively included in the highest risk category The index scores are calculated from the ratio of the number of miles constructed in a given time period to the total system Page 32 of 36 Example Pipeline Safety Program Plan miles Index #3.5: Coating and Cathodic Protection Cathodic protection of steel pipe is critical in preventing metal loss and the potential for pipeline leaks or failures due to corrosion The Annual Report contains data on the external corrosion protection of steel pipe and the amount of cast iron pipe The inputs into the risk model from the Annual Report and the associated assigned weighting factors are:  The number of miles of cast iron pipe 10  The number of miles of bare, unprotected steel pipe 10  The number of miles of coated, unprotected steel pipe  The number of miles of bare, cathodically protected steel pipe  The number of miles of coated, cathodically protected steel pipe The index scores are calculated based on the ratio of the number of miles in each category to the total number of miles of pipe Index #3.6: Excavation Activity The amount of excavation activity along the right-of-way is an indicator of third-party risk An index has been included for excavation activity that is the normalized ratio of location-requests per 1000 services The operator’s ratio of excavation damages to excavation “one-call” notifications can be to national or regional averages to evaluate the effectiveness of their damage prevention activities Risk Index #4: Historical Performance An index has been included that allows the State program manager to input a “Letter Grade” that represents an estimate of the performance of an operator Several parameters should be considered that might reflect an operator’s historical performance in areas that are related to overall safety and integrity management These include enforcement actions taken, and the State’s experience with an operator’s integrity and compliance performance The possible grades range from to 10, with being assigned to the best performing operators and assigned to the worst performing (riskiest) operators Final Relative Risk Score There are statistical indices that are indicative of the relative likelihood of incidents They are indices 1, 2, 3.2, 3.4 and 3.5 Each index is weighted equally There are statistical indices indicative of the relative consequences of incidents They are indices 3.1 and 3.3 The principal factor is HCA mileage (item 3.1) which is weighted by the score for pipe diameter (item 3.3) Using the classical definition of Risk = Likelihood x Consequences, the resulting risk score using operator statistics is based on the following equation: Risk Index = [Index + Index + Index 3.2 + Index 3.4 + Index 3.5] * [(Index 3.1)(Index 3.3)] The total risk score based on operator statistics is further refined based on the State’s experience using the historical integrity and compliance performance factor (overall risk index 4), as follows: Adjusted Relative Risk = Risk Index * Index This adjusted relative risk score can be compared among operators as an aid to prioritizing inspections This Page 33 of 36 Example Pipeline Safety Program Plan relative risk model is summarized in Table 1, below Summary The example risk methodology presented above utilizes easily retrievable data from existing reports that are required to be submitted to PHMSA by pipeline operators Excel spreadsheets have been created into which the data from these reports is input and which then calculate an operator-specific relative risk factor that can be used to aid in developing an Inspections Priority List The risk algorithm and related weighting factors can be fine tuned based on experience Adjustments could include expansion of the types of data analyzed, adjustments to the normalization scale, adjustments to the weighting factors, etc Page 34 of 36 Example Pipeline Safety Program Plan TABLE Risk Index – Data Used – Source of Data (TTM) - Total Transmission Miles (THM) - Total HCA Miles (BAM) - Total HCA miles with completed Baseline Assessments (TMM) – Total Miles Distribution Main (TNS) – Total Number of Services (TSM) – Total System Miles TTM THM BAM TMM TNS TTM + TMM Risk Index Calculation Index #1: Incident History (use latest PHMSA Incident Report Data) (F) - Fatalities (previous years) (I) Injuries (previous years) (P) Number of Incidents w property damage (previous years) Index #1 (Incident History) = Weighted Incident totals 10(F) 7(I) 2(P) 10(F) + 7(I) + 2(P) Index #2: Cause of Leaks (use latest annual report) (Lc) - Number of leaks caused by corrosion (Ln) - Number of leaks caused by natural forces (Le) - Number of leaks caused by excavation (Lo) - Number of leaks caused by other outside forces (Lm) - Number of leaks caused by material and welds (Lop) - Number of leaks caused by equipment and operations (Lother) - Number of leaks caused by "other" Index #2 (Cause of Leaks) = Normalized per 1000 miles (Lc)/(TSM/1000) (Ln)/(TSM/1000) (Le)/(TSM/1000) (Lo)/(TSM/1000) (Lm)/(TSM/1000) (Lop)/(TSM/1000) (Lother)/(TSM/1000) (Lc+Ln+Le+Lo+Lm+Lop+Lother)(TSM) Index #3.1: HCA mileage (use IMP performance metrics report) = THM Index #3.2: Repairs (Ri) - Number of Immediate Repairs (all baseline assessments) (Rs) - Number of Scheduled Repairs (all baseline assessments) Index #3.2 (Repairs) = Weighted and Normalized per 1000 miles of completed assessments (Ri)/(BAM/1000) 0.1(Rs)/(BAM/1000) (Ri+ 0.1Rs)/(BAM/1000) Index #3.3: Diameter of Pipelines (use most recent annual report) (M0) - Number of miles of pipe with diameter inch or less (M4) - Number of miles of pipe with diamter >4 inch to 10 inch (M10) - Number of miles of pipe with diameter >10 inch to 20 inch (M20) - Number of miles of pipe with diameter >20 inch to 28 inch (M28) - Number of miles of pipe with diameter >28 inch (Mu) - Number of miles of pipe with unknown diameter Index #3.3 (Size) = Scored as a weighted % of total system miles 1(M0)/TSM 2(M4)/TSM 4(M10)/TSM 8(M20)/TSM 10(M28)/TSM 10(Mu)/TSM (1(M0) + 2(M4) = 4(M10) + 8(M20) + 10(M28) + 10(Mu))/TSM Index #3.4: Age of Pipelines (use most recent annual report) (Au) - Number of miles of pipe constructed in an unknown time period (A39) - Number of miles of pipe constructed pre 1940 (A49) - Number of miles of pipe constructed in period 1940-1949 (A59) - Number of miles of pipe constructed in period 1950-1950 (A69) - Number of miles of pipe constructed in period 1960-1969 (A79) - Number of miles of pipe constructed in period 1970-1979 (A89) - Number of miles of pipe constructed in period 1980-1989 (A99) - Number of miles of pipe constructed in period 1990-1999 (A09) - Number of miles of pipe constructed in period 2000-2009 Index #3.4 (Age) = Scored as a weighted % of total system miles 10(Au)/TSM 10(A39)/TSM 8(A49)/TSM 8(A59)/TSM 8(A69)/TSM 5(A79)/TSM 5(A89)/TSM 5(A99)/TSM 2(A09)/TSM (10(Au+A39) + 8(A49+A59+A69) + 5(A79+A89+A99) + 2(A09))/TSM Index #3.5: Coating & CP (use most recent annual report) (Ic) - Number of miles of cast iron pipe (Bu) - Number of miles of bare unprotected steel pipe (Cu) - Number of miles of coated, unprotected steel pipe (Bp) - Number of miles of bare, cathodically protected steel pipe (Cp) - Number of miles of coated, cathodically protected steel pipe Index #3.4 (Age) = Scored as a weighted % of total system miles 10(Ic)/TSM 10(Bu)/TSM 5(Cu)/TSM 4(Bp)/TSM 2(Cp)/TSM (10(Ic)+10(Bu) + 5(Cu) + 4(Bp) + 2(Cp))/TSM Index #3.6: Excavation activity (use most recent annual report) = (LOC) – Number of locate requests Normalized per 1000 services LOC/(TNS/1000) Index #4: Historical Operator Performance Subjective input of inspectors State inspector subjective input (best) to 10 (worst) Likelihood Index Total = Consequence Index Total = Index #1 + Index #2 + Index #3.2 + Index #3.4 + Index #3.5 + Index #3.6 Index #3.1 * Index #3.3 Page 35 of 36 Example Pipeline Safety Program Plan Overall Risk Index Total = Adjusted Risk Index Total = (Likelihood Index) (Consequence Index) (Overall Risk Index) (Index #4) Appendix C – Forms [insert forms, checklists, inspection aides, etc.] Appendix D – Operator Contact List [insert operator contact list] Appendix E – Federal Statute [insert copy of federal statute] Appendix F – Federal Regulations [insert copy of federal regulations] Appendix G – State Statute [insert copy of state statute] Appendix H – State Regulations [insert copy of state regulations] Page 36 of 36